SUMMER 2005
E L E C T R I C
P O W E R
Deploying advanced
Coal Plants
A lso I n t h is I ssue :
Mercury Emissions
Control
Power Grid Security
R E S E A R C H
I N S T I T U T E
ELECTRIC POWER
RESEARCH INSTITUTE
The Electric Power Research Institute (EPRI), with major locations
in Palo Alto, California, and Charlotte, North Carolina, was
established in 1973 as an independent, nonprofit center for public
interest energy and environmental research. EPRI brings together
members, participants, the Institute’s scientists and engineers, and
other leading experts to work collaboratively on solutions to the
challenges of electric power. These solutions span nearly every
area of electricity generation, delivery, and use, including health,
safety, and environment. EPRI’s members represent over 90% of the
electricity generated in the United States. International participation
represents nearly 15% of EPRI’s total research, development, and
demonstration program.
Together. . . Shaping the Future of Electricity
Staff and Contributors
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COVER: Commercial deployment of advanced clean coal power plants will allow the nation to
make use of its tremendous coal resources while meeting ever-tightening air qualtiy regulations.
(Art by Craig Diskowski/Edge Design)
SUMMER 2005
16
6
26
Editorial
F e at u r es
Depa r tme n t s
2 A Window Into EPRI
16 Mercury Control for Coal-Fired
Power Plants
3 Contributors
No commercial technologies yet exist
to fully control mercury emissions from
coal plants, but several approaches that
have shown good potential in full-scale
tests are now nearing market readiness.
4 Innovation
C ov e r S t o ry
6 Coal-Based Generation at the Crossroads
CoalFleet for Tomorrow—an industrydriven initiative—hopes to speed the
­deployment of advanced clean coal
power plants by reducing the technical
and cost barriers to market acceptance.
26 Grid Security in the 21st Century
A new, industrywide initiative focuses on
protecting electric power systems from
computer hackers and worse.
34 Technology at Work
LI S TIN G S
36 Technical Reports & Software
40 EPRI Events
Editorial
A Window Into EPRI
One of the great pleasures of my first year at EPRI
is to announce the relaunch of its flagship publication, the EPRI Journal. I very much enjoyed
reading the Journal while I was at GE. It was an
effective window into EPRI, providing an indepth understand­ing of the content and value of
EPRI’s programs and communicating the broader
business and social contexts of the industry’s most
pressing issues. The Journal also captures something that is easy to miss in a technical portfolio
as varied and rich as EPRI’s: the power and value
of pursuing com­prehensive, integrative approaches.
This highly ­coordinated route allows EPRI to
accomplish things that others cannot. It capitalizes
on the unique advantages of the collaborative
model—bringing people, ideas, perspective, money,
and expertise to bear on the truly difficult issues
we face now and for the future. It is important
that the Journal readers get this “big picture” of
what the Institute is doing.
One of the best examples of collaborative advantage is EPRI’s CoalFleet initiative, the topic of this
first issue’s cover story. Deployment and commercialization of advanced, clean coal generation
technologies carries all of the difficulties of transformational change: a wide and disparate slate
of stakeholders, hard technical challenges, cost
uncertainties, regulatory unknowns, and stubborn
market barriers. Yet we have here technologies that
clearly speak to the needs and constraints of the
coming decades. This is the kind of challenge that
will only yield to the collaborative approach.
Steven Specker
President and Chief Executive Officer
E P R I
J O U R N A L
And while CoalFleet is a key initiative for
electricity’s future, it is only a piece of the larger,
tougher question that I believe will define the
power industry over the coming decades: how will
we provide clean, affordable electricity in an
increasingly carbon-constrained world? There is
no silver bullet on this issue. We will solve the
problem only by thinking beyond individual
technologies, by considering a full complement of
options that together can satisfy our energy needs
in the new technical/environmental/­societal
context that we now see evolving across the globe.
Carbon constraints will require the broadest, most
innovative thinking we can muster. It will require
the ability to look beyond a seemingly endless
succession of difficult milestones and embrace a
goal that must and will be achieved. As with any
endeavor of this size and importance, our success
­depends on commitment, hard work, and strong
leadership—essentials that EPRI is well-equipped
and willing to provide.
I have much more to say about the challenges
facing our electricity system, present and future,
and I expect to do so in subsequent issues. For
now, I encourage you to read and enjoy the new
EPRI Journal. We have an exciting lineup of
articles planned for the coming year that I’m sure
will be both interesting and useful. And if you
have ideas about how we can use the magazine to
improve the service and value you derive from the
Institute, please let me know—it is a window into
EPRI that is designed to be open.
Contributors
Coal-Based Generation at the Crossroads
(page 6) was written by science writer Taylor Moore with
­technical assistance from Stu Dalton and Jack Parkes.
planetary sciences from MIT, an MS in atmospheric sciences
from the University of Washington, and a PhD in meteorology
from the University of Maryland.
director of EPRI’s Generation
Sector, came to the Institute in 1976, having
previously worked for Pacific Gas & Electric
and Babcock & Wilcox. From 1979 to 1994,
he headed EPRI’s SO2 control and integrated
emissions areas. For the last 10 years, he
has managed and developed strategy for broad areas of the
advanced coal and emissions control R&D portfolio. Dalton
holds a BS in chemical engineering from the University of
California at Berkeley.
a technical executive for
air emissions and coal combustion product
management, has been with EPRI since 1985.
He started the Institute’s program on mercury
control technology R&D in the late 1980s
and expanded it into the Integrated Environmental Control program several years ago. Offen coordinates
EPRI’s collaborations with DOE and EPA in air emission control technology. He holds BS and PhD degrees from Stanford
University in mechanical engineering and an MS from MIT in
the same field.
Stu Dalton,
has held senior management
posi­tions at EPRI, Bechtel, Ebasco, and GE
involving the design, reliability, and perform­
ance of coal-based power plants and sys­tems.
In his current EPRI position, area manager
for advanced generation, he directs the CoalFleet for Tomorrow Initiative. Parkes received a BS from The
Queens University of Belfast and an MS from Union College
in New York, both in mechanical engineering. He also earned
an MBA from the University of Santa Clara in California.
George Offen,
Jack Parkes
Mercury Control for Coal-Fired Power Plants
(page 16) was written by science writer Paul Haase with guidance from Leonard Levin and George Offen.
Grid Security in the 21st Century (page 26) was written by science writer John Douglas with technical information
from Robert Schainker.
is a technical executive in
EPRI’s Power Delivery and Markets Sector
with a current focus on electricity grid infrastructure security and power quality. Before
joining the Institute in 1978, he was with
Systems Control, Inc., of Palo Alto for 10
years, specializing in utility SCADA and energy management
systems. Schainker has a BS in mechanical engineering, an MS
in electrical engineering, and a PhD in applied mathematics,
all from Washington University in St. Louis.
Robert Schainker
is EPRI’s technical leader for
air toxics health and risk assessment, specializing in multimedia cycling and ­exposure,
chemical transport, and atmospheric physics.
Before coming to EPRI in 1986, he worked
for six years as a senior scientist at WoodwardClyde Consultants and earlier at Science Appli­cations International. Levin has a BS degree in earth, atmo­spheric, and
Leonard Levin
S U M M E R
2 0 0 5
Innovation
Largest Silicon Carbide
Switch Demonstrated
Widespread use of solid-state devices to
control power flow on utility networks
will require substantial reduction in
cost and improvement in availability
compared to the silicon-based controllers available today. Achieving such
performance enhancements will involve
replacing silicon in these devices with
­advanced semiconductors that can
switch larger currents at higher voltages and oper­ate at higher temperatures.
The most prom­ising near-term candidate is silicon carbide (SiC), and recent
­advances have brought SiC switches
much closer to commercial applications
in the power industry.
A key performance characteristic
of semiconductor materials is their
so-called “bandgap”—the amount
of energy needed to release
electrons bound in the
crystalline structure so
they can move freely
and thus conduct
electricity. Widebandgap semiconductors, such as SiC, are able
to withstand considerably
higher voltages and temperatures
before conduction begins, so power
controllers made from them can be
smaller and more robust, and not need
as much auxiliary cooling equipment.
This development could make large
solid-state devices, such as flexible ac
transmission system (FACTS) controllers, more competitive.
The main barrier to using wide-bandgap materials in electronic switches has
been crystal defects that limit their performance. Since 1996, EPRI has sponsored research aimed at improving the
E P R I
J O U R N A L
Emerging technologies and
cutting-edge engineering
quality of these materials, together with
finding better ways of fabricating useful
devices based on them. Last year, this
work paid off with a major achievement:
demonstration of the largest, fastest,
most powerful SiC switch ever made—a
1-cm2 device that could switch power
of 1750 volts and 250 amperes while
operating at 250°C. That’s twice as large
as any earlier SiC switch, with about 100
times greater current-carrying capacity,
and demonstrates the technology’s potential for use in large-scale devices.
This accomplishment brings commercialization of power control devices
based on wide-bandgap semiconductors much closer to reality, according to
project manager Ben Damsky. “Within
about five years, I believe we could
see silicon carbide used in devices
ranging from FACTS controllers
for power networks to power
conditioning equipment
for consumer electronics,” he says. “The
impact will probably be the greatest
in high-voltage utility
applications, where the
cost of FACTS devices could
potentially be reduced by about
one-third and availability increased
significantly.”
Maintaining high availability is
particularly critical in power system
applications, and today’s large solid-state
controllers have had difficulty achieving
availability factors greater than 96%.
The largest contributor to down time for
these installations is the auxiliary cooling
system, which is essential because siliconbased devices must be derated if they
reach 125°C. A SiC device operating at
250–300°C could have a much ­simpler
cooling system that would require
less maintenance. Eventually, a highly
­reliable passive cooling system with no
moving parts may become possible.
The next challenge will be to translate
the accomplishments achieved so far in
a laboratory setting into commercialscale production of SiC switches. Future
work is expected to focus particularly
on manufacturing and characterizing
SiC devices rated up to 5000 volts and
1000 amperes, while also testing their
performance under a variety of operating
conditions. Eventually, other wide-bandgap semiconductors may also be used in
high-power controllers, further reducing
their size and cost.
For further information, contact Ben
Damsky, bdamsky@epri.com.
Virtual Reality Simulation
to Reduce Nuclear
Construction Costs
Advanced visualization technology
promises to reduce the cost of building
nuclear power plants and other complex
industrial facilities by optimizing the
construction sequence, streamlining the
schedule, and identifying potential
problems before they are encountered
in the field. The technology represents
an extension of conventional 3-D
­computer-aided design by adding the
fourth “dimension” of time to the
modeling process so that engineers can
simulate the construction sequence in
unprecedented detail.
Developed through collaboration
between EPRI and Westinghouse, the
4-D visualization technology is being
integrated into the design process of
two Westinghouse advanced light water
reactors. For one of the reactors, more
than five months were removed from
alternative construction paths for large
plant modules, and simulated “con­
struction” of representative modules in
isolation. The technology can also be
used to prepare and train construction
crews, verify achievable construction
schedules, and enhance the confidence
of potential investors in the timing of
capital recovery.
“Our studies with Westinghouse
indicate that EPRI’s virtual reality construction technology should cut about
10% off construction times for the next
generation of nuclear plants, which will
help them to be more competitive,” says
project manager Layla Sandell. “Our
next step will be to extend the technology to nuclear plant designs from
­additional vendors.”
For further information, contact Layla
Sandell, lsandell@epri.com.
the projected construction schedule
without reducing the duration of any
­individual activity. Optimized sequencing of tasks also reduced the expected
on-site requirements for skilled craft
labor (e.g., concrete workers and pipe
fitters) by several months.
The detail and specificity of the
­animated modeling allows examination
of issues as varied as crane placement,
MagMolecules Selectively
Remove Contaminants From
Liquid Waste
Processing low-level waste (LLW) effluent streams from nuclear plants remains
a persistent challenge because the dissolved radioactive contaminants may be
present in only minute quantities so that
removing them from a large volume of
liquid is difficult and expensive. Evaporation, for example, leaves a solid waste
product in which the radionuclides may
represent only a small fraction of the
total material that must then be disposed
of. Ion exchange systems can remove
contaminants more selectively, but still
produces an unnecessarily large volume
of solid waste.
Now an innovative new approach
promises to greatly reduce radioactive
waste volume by using magnetic molecules that target specific radionuclides
dissolved in an LLW stream. Called
the MagMolecule process, for which
EPRI has filed a patent application, the
technology is also expected to be used
in other important applications, such as
removing heavy metals from industrial
effluents and groundwater.
“Laboratory results indicate that MagMolecule technology has the potential
for reducing waste volume by a factor of
up to 5000, compared to conventional
ion exchange treatment,” according to
project manager Sean Bushart. “The
­result would be significant cost savings for low-level waste management
in nuclear power plants, as well as for
applications in other industries.”
The concept is based on the use of
proteins called ferritins, which the body
uses to store iron, for example, in the
spleen and liver. Synthetically produced
and magnetically stronger “magnetoferritins” are used in the computer industry to manufacture data storage disks.
EPRI’s research has focused on modifying magneto-ferritins to bind selectively
to specific contaminants—initially strontium and cesium, and now cobalt—that
represent important radioactive constituents of LLW. The bound ferritincontaminant complex is then removed
from the effluent stream by a reusable
magnetic filter, which is backwashed to
collect the solid by-products.
Now that technical feasibility of the
MagMolecule process has been established in the laboratory, the next step
will be to scale up the technology for
pilot application in the field. Specifically,
by the end of this year, researchers hope
to test the process using actual nuclear
plant effluent, while also improving the
associated filtration and instrumentation
systems. Bushart says that commercialization of MagMolecule technology may
come in as little as two years.
For further information, contact Sean
Bushart, sbushart@epri.com.
S U M M E R
2 0 0 5
Coal-Based
generation
at the crossroads
by Taylor Moore
The Story
in Brief
Offering clean electricity
generation from an abundant
fuel, advanced coal technologies seem tailor-made for a
power industry facing evertighter environmental regulations. But committing to new
approaches—and the inevitably higher cost of first-of-a-kind
units—is always a difficult
business proposition. To help
break through the final barriers
to market acceptance, EPRI
is leading an industry-driven
initiative to speed the deployment of new clean coal plants
and support the development
of next-generation designs.
Wellhead Price of Natural Gas ($/million Btu)
ong the workhorse of electric generating systems around the world, coalbased power plants are increasingly
seen as one of the most economic choices
for meeting future growth in demand
for power. But while today’s units operate far more cleanly than when air-quality rules were ramped up in the 1970s,
coal-burning plants are still constantly
chasing tighter regulatory limits on emissions through the refinement of add-on
cleanup technologies. Now a new generation of advanced, clean coal power plants
that integrate emissions reduction into
their basic designs stands at the threshold
of commercial deployment. These plants
not only address the sulfur and nitrogen
oxides at the center of today’s air quality
regulations more efficiently, but also carry
advantages in removing carbon dioxide
(CO2), which may be regulated in the future because of its role as a greenhouse gas
associated with global climate change.
Such clean coal technologies have been
evolving for more than two decades; the
last major hurdle to reaching technological maturity and, in turn, economic
competitiveness with conventional coal
plants is the demonstration of their commercial viability and reliable operation at
full-scale by utilities and power generators. Expanded operating experience with
advanced coal generating systems is essential for convincing prospective investors
that the costs and risks are well understood and manageable. And getting more
such plants built and operating is critical
for the necessary engineering development that will take the technology from
first-of-a-kind plants to fully optimized,
“learned out” units with costs as low as
designers can eventually drive them.
To accelerate commercial deployment
of advanced clean coal power systems, the
electric utility industry is leading a broadbased collaborative program encompassing the development, demonstration, and
deployment of technologies including
integrated gasification combined-cycle
(IGCC), ultra-supercritical pulverized
coal (USC PC), and supercritical circulating fluidized-bed combustion (SC FBC).
Known as CoalFleet for Tomorrow, or
simply “CoalFleet,” the initiative aims to
tackle the technical, economic, and institutional challenges to making clean coal
6
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3
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0
1975
1980
1985
1990
1995
2000
2005
The low capital cost, quick construction, and relatively straightforward permitting of gas-fired power
plants made them by far the top choice for new generation capacity over the past decade. However,
a near tripling of the wellhead price of natural gas in recent years has changed the cost equation
substantially, making advanced coal generation options more attractive for strategic additions.
E P R I
J O U R N A L
power systems a prudent investment
­option for both the short run and the
long run. By collaborating across all sectors of the power industry, CoalFleet is
focused on breaking through the impasse
of the longstanding conundrum of advanced clean coal technologies: despite
wide agreement on their ultimate need
and value—and on the magnitude of investment and long lead time required to
reach commercial maturity—there is still
inadequate commitment of resources to
bring these advanced systems to fruition.
EPRI organized the CoalFleet initiative
with broad input from and on behalf of
the industry as a vehicle for mutual co­
operation in speeding the deployment of
advanced clean coal plants and in introducing next-generation designs.
Hank Courtright, EPRI’s vice president for generation, explains: “CoalFleet’s
goal is to preserve this abundant source of
fuel as a vital component in the electricity
generation mix. Work must begin now to
ensure that the advanced coal technologies can establish a solid track record—
before large numbers of coal plant replacements become necessary. We see the
need to get plants built and operating
soon in order to gain experience with
and reduce the cost of advanced coal
plant technology.”
In the near term, CoalFleet is focused
on incorporating user-defined requirements and lessons learned from existing
advanced plants into new designs that
will be developed for commercial orders
anticipated over the next decade. To accomplish this, the initiative has assembled
teams of engineers and other technical experts to advise and provide input to early
deployers of new advanced coal technologies and their technology suppliers. In
turn, the early deployers have agreed to
make general design basis and nonpro­
prietary engineering information available to all CoalFleet participants with the
aim of help­ing spur reductions in capital
costs and risks for subsequent orders as
well as improvements in plant availability
and performance.
Bituminous
Subbituminous
Lignite
Economic and engineering studies have shown that costs and performance for advanced coal technologies vary significantly with the type of coal
they use. Because there are substantial regional differences in coal type, several advanced technologies—IGCC, USC PC, and SC CFBC—must be
developed to fully utilize the nation’s tremendous coal reserves. (Source: USGS)
CoalFleet for Tomorrow is already gain­ing a high degree of visibility among the
utility and power generation technology industry. Over 40 organizations have
committed so far to support the initiative,
including energy companies representing
more than half of all presently installed
U.S. coal-fired generating capacity, major
coal-based European generators, leading
power equipment manufacturers, technology suppliers, and the U.S. Department of Energy (DOE).
Policymakers are taking notice as well.
Earlier this year, the U.S. Congress took
under consideration various possible financial incentives that may help close
the current gap in the levelized cost of
electricity (COE) between conventional
coal plants, which produce much of the
nation’s lowest-cost electricity, and the
15–20% higher COE expected for the
next several advanced coal plants that
may be built. EPRI provided valuable
data and insight as input for congressional
deliberations.
Changing Times
Turn the Tables
Despite the abundance and consistently
low cost of coal as a generating fuel, few
coal-fired power plants have been built
around the world for well over a decade,
except in Asia. Instead, the lower capital
costs, quicker construction, and more
straightforward permitting for natural
gas–fired plants led utilities and generating companies that needed additional capacity to favor these units, at least while
natural gas prices remained relatively low.
In the past seven years, over 200 GW of
gas-fired generating capacity have been
built in the United States, compared with
about 15 GW of coal-fired capacity. A similar preference was followed in Europe.
Today, far different economic conditions apply: oil and natural gas prices have
both set new record highs in recent years.
As a result, many gas-fired combinedcycle plants are being called on to gen­erate at only a fraction of their planned
capacity factor. The average capacity factor for such plants in 2003 was 32% and
continued to decline into 2004, making
many of the units poor performers as
­financial assets. Gas prices are forecast to
remain high as a result of supply and demand imbalances and transportation
bottlenecks. Increases in imports of oil
and liquefied natural gas, while potentially reducing the volatility of natural gas
prices, are also heightening concerns over
energy security and international trade
balance. Together, these factors are making the economics of coal power appear
more attractive to both power generators
and government agencies.
S U M M E R
2 0 0 5
Coal
Water
Oxygen
1
Gasifier
Exhaust Stack
3
4
Electricity
Water
Electricity
Clean Syngas
Steam
6
5
Sulfur
2
Ash
In IGCC plants, coal is not burned directly, but rather is processed with oxygen and water in a high-pressure gasifier (1) to form a synthesis gas.
Ash forms a slag (2) that is removed from the gasifier for disposal or commercial use. The syngas is cooled (3) and stripped of sulfur compounds
(4), which are converted to elemental sulfur that can also be sold commercially. The clean syngas is then combusted in a gas turbine/generator
(5), which generates most of the electricity the plant produces. The waste heat is recovered and used to produce steam that drives a smaller
turbine/generator (6) in a combined-cycle configuration to produce additional electricity.
Meanwhile, environmental advocates
and regulators are maintaining pressure
on coal plant operators to further reduce
emissions. As a result, new coal plants will
need to have substantially lower emissions, despite the industry’s impressive
achievements in reducing emissions from
the current fleet of plants. Future requirements for controls on CO2 emissions from
new plants under consideration today
could significantly influence decisions on
technology selection and design.
Conventional coal plant technologies
offer lower capital costs and lower projected costs of electricity than today’s
handful of advanced generating systems;
however, looming environmental restrictions that could lead to requirements to
retrofit emissions control equipment or to
purchase emission allowances creates uncertainty over which coal technologies
will actually be the most economical over
various design lifetimes. The answer is also
10
E P R I
J O U R N A L
influenced by location and the economics
of fuel supplies. Given the diversity of regional electricity markets and the variability in the properties of economical
coals among regions, a portfolio of advanced coal power systems—including
IGCC, USC PC, and SC CFBC—is
needed to comprehensively meet the needs
of the market.
IGCC systems combine the high efficiency and low emissions of gas turbines
with the ability to run on syngas, which
is coal-derived, or other low-cost solid
or heavy liquid fuels. But as Stu Dalton,
EPRI director for generation, told the
Senate Energy and Natural Resources
Committee’s Coal Conference last April,
“Electricity from initial IGCC plants
without CO2 capture and storage will
cost 15–20% more than electricity from
conventional coal power units with SO2
and NOx emission controls. Additional
experience with full-scale IGCC plants
will likely reduce or eliminate this cost
differential. Incentives will be needed
to deploy these initial IGCC plants in
order to overcome higher capital costs
and technology risks,” Dalton told the
conference.
IGCC’s relative competitiveness with
conventional, pulverized-coal plants firing bituminous coal improves if CO2 removal is required, but such a requirement
significantly reduces the power output
and increases the cost of both plant types.
Studies by EPRI, DOE, and others have
found that the incremental cost penalty
for removing CO2 from high-pressure
IGCC syngas is about 25% on a levelized
COE basis, whereas the cost penalty for
removing it from the flue gas of a conventional coal plant is about 70%. Additional costs for transporting and storing captured CO2 are not included in the
calculation, but would be comparable for
both plant types.
3500 psi
2400 psi
37
1000
1200
1400
Steam Temperature (°F)
Improvements in materials are allowing
pulverized coal plants to operate at higher
temperatures and pressures, which increases
plant efficiency and reduces the release of
CO2 and other emissions. Ultra-supercritical
plants are already in use in Europe and
Japan, with steam temperatures of 1120°F
and pressures of 4200 psi. Units with steam
temperatures up to 1400°F and pressures up
to 5000 psi are expected to be demonstrated
in the United States within 10–15 years.
The economics of IGCC technologies
demonstrated so far in the United States
are less favorable for lower-rank coals such
as subbituminous or lignite that predominate the resource in certain regions, as the
technologies currently work best using
the higher-rank bituminous coal typical
of many commercially mined coal deposits east of the Mississippi River. Design
changes or success with the advanced, dryfeed compact gasification systems now
under development by DOE and industry partners may eventually make IGCC
more economical for low-rank fuels.
For regions where low-rank fuels predominate, USC PC and SC CFBC may
be the most cost-effective advanced coal
options. For large-scale coal plants burning very low-grade fuels, new supercritical
CFBC designs are a high-performance,
cost-effective option. Meanwhile, worldwide advances in boiler and turbine materials that have greater strength at high
Strategy for Deploying
Advanced Coal Technologies
To provide technical input and advice to
a slate of task working groups and earlySC CFBC
Plants
USC PC &
IGCC Plants
Mercury
Capture
NOX Reduction
Pulverized Coal Plants
CO2 Capture
& Storage
SO2 Capture
Research
Development Demonstration
Deployment
Mature
plants
39
3500 psi
Next-generation
commercial plants
41
5000 psi
deployment project owners under the
CoalFleet for Tomorrow Initiative, EPRI
formed the CoalFleet World-Class Expert
Working Group, composed of key EPRI
personnel, independent industry experts
in advanced coal technologies, and utility
representatives with advanced coal plant
operating experience. The expert working group is developing a comprehensive
strategy for surmounting the so-called
“mountain of death” (high cost of market-entry units) that new technologies in
general and advanced coal technologies in
particular must overcome before reaching technological maturity and the lowest
achievable cost. According to Jack Parkes,
EPRI’s area manager for CoalFleet, “The
strategy is closely examining ways to remove barriers that have hindered the implementation of advanced coal systems,
including high capital and construction
costs, inadequate reliability, long project
schedules, lack of standardization, and
dif­ficult environmental permitting procedures. Optimizing, modularizing, and
standardizing plant designs for a range of
technologies, coal types, regional issues,
and types of owner/deployer organization are the keys to reducing the time,
Full-scale earlydeployment plants
43
1st demonstration
plants in service
45
Ultra-supercritical 5000 psi
Supercritical
Subcritical
5000 psi
Capital Cost per Unit of Capacity
Efficiency (%), High Heating Value
47
temperatures and less susceptibility to
thermal creep and fatigue have enabled
the emergence of reliable pulverized-coal
plants operating with main steam conditions in the ultra-supercritical range.
Such plants are already in operation in Japan and parts of Europe, where high fuel
prices place a premium on efficiency.
“Limits on CO2 emissions in the United States would have a comparable pricedriver effect on the cost of electricity from
conventional coal-fired plants,” explains
Dalton. “DOE, EPRI, and other organizations are working to develop long-lived,
reliable components for ultra-supercritical PC units with main steam temperatures up to 1400°F (760°C) and pressures
up to 5000 psi (340 bar). Plants operating at such steam conditions are expected
to achieve generating efficiencies topping
45% on a higher heating value basis and
to reduce CO2 and other emissions by
15–22% compared with current conventional plants.”
Mature Technology
Time
The difficult—and costly—process of bringing a new technology into the marketplace has been
called the “mountain of death.” Advanced coal technologies are nearing the crest of the curve,
but the high cost of first-of-a-kind plants can often stall a new technology in the demonstration
stage. The primary focus of the CoalFleet initiative is to get the first group of full-scale advanced
coal plants deployed as early as possible.
S U M M E R
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11
Incentives for Advanced Coal Plant Deployment
The current estimated cost of electricity from initial IGCC plants is
about 15-20% more than that from a conventional pulverized-coal
plant when higher capital and fixed costs are accounted for and an
allowance is included for the risk of potential shortfalls in the IGCC
plant’s availability. In light of this, CoalFleet members expect that
financial incentives will be needed to spur initial plant deployment
and provide the design and operational experience necessary to
reduce cost and demonstrate reliable performance.
12
Tom Wilson, EPRI senior technical manager for climate change, who
conducted the analyses along with Charles Clark, an analyst working
with EPRI for the CoalFleet for Tomorrow Initiative, explored how various
combinations of incentives might work. In an article for Public Utilities
Fortnightly, the two noted, for example, that doubling the base-case investment tax credit from 10% to 20% and combining it with accelerated
depreciation would come close to closing the cost gap for IOUs and
IPPs. Alternatively, doubling the production tax credit to equal that cur-
EPRI and CoalFleet participants have analyzed financial incentives
rently available for wind energy facilities could actually make IGCC’s
that potentially could reduce the incremental cost gap of IGCC plants
COE less than that of conventional PC for taxable entities. A third pack-
for early deployers. In particular, the CoalFleet Incentives Task Work-
age of incentives—tripling the federal government’s cost-sharing to 30%
ing Group examined eight types of federal financial incentives: loan
without repayment and adding availability insurance—would provide
guarantees, direct federal loans, federal cost-sharing grants, investment
public power producers and cooperatives with sufficient cost-reduction
tax credits, production tax credits, tax-exempt financing, accelerated
to make IGCC attractive compared with conventional PC. The gap
depreciation, and the new concept of federal availability insurance.
would still not be closed for IOUs and IPPs, “but the difference is small
Their analysis considered three types of power producers—regulated
enough that other considerations might well determine their choice,”
investor-owned utilities (IOUs), independent power producers (IPPs) with
Wilson and Clark note.
contracts for their plants’ generating output, and public power produc-
“In the end, however, it must be remembered that any incentives
ers (cooperatives, municipal utilities, and federal and state entities)—
such as those just discussed are intended only to get IGCC ‘over the
and accounted for differences among them in borrowing costs and
hump’ of initial commercial deployment,” the analysts point out. “After
tax obligations. The findings were tabulated in terms of the effect of an
that, commercial attractiveness of this prototypical clean coal technol-
incentive on an IGCC plant’s levelized cost of electricity (COE).
ogy will depend on a variety of other factors. Foremost among these
No single type of fully evaluated incentive bridged the COE gap
will be resolution of the technical risks involved, specifically by showing
between IGCC and PC plants for all company types. Moreover, varia-
that IGCC plants can achieve sufficiently high availability to compete
tion in the value of different incentives to various types of power produc-
with conventional coal plants. Initial capital costs should also decline
ers was substantial. For example, public power producers receive no
with design and operational experience and as the infrastructure for
direct benefit from tax-based incentives, and loan guarantees provide
building, maintaining, and utilizing IGCC facilities develops. Additional
much greater benefit to IPPs than they do to other producer types. “As a
factors that may influence the long-term attractiveness of IGCC technol-
result, CoalFleet members have concluded that combinations of incen-
ogy include the potential need to capture and sequester CO2 to miti-
tives, or tailored packages of incentives, will be necessary to signifi-
gate global warming or to produce hydrogen for future fleets of fuel-cell
cantly lower the cost barrier to IGCC deployment and to give relatively
vehicles. Because of this potential, the ultimate value of IGCC may be
equal incentive to all power producers,” says EPRI’s Jack Parkes. “Par-
its importance as a hedging strategy—a way to keep using the nation’s
ticularly interesting with respect to the equitability aspect is the newly
most abundant energy resource while providing options to deal with
developed concept of availability insurance.” In this type of incentive,
long-term environmental hazards.”
the federal government would provide insurance for covered plants
EPRI is coordinating CoalFleet’s deployment incentives analyses
that are unable to meet a specified target for availability. Although
with DOE to ensure that the impact of incentives on federal budgets
analyses showed that availability insurance alone would not close the
is properly calculated. CoalFleet plans to update its incentives analy-
cost gap and make IGCC competitive with conventional pulverized
ses on the basis of peer review comments, evaluate additional types
coal, such an incentive may be valuable and effective in combination
of incentives, and extend the analysis to address a broader range of
with other incentives.
technology options.
E P R I
J O U R N A L
fits of standard, or reference, designs for
Supporting Early-Deployment
IGCC and other advanced coal plants.
Projects
As with the UDBS documents, CoalThe operating concept for CoalFleet is
Fleet’s goal is to create standard plant
“learning by doing,” with EPRI and the
independent experts participating direct- design guidelines for each major IGCC
ly in the site-specific engineering feasibil- gasifier technology and its applicable fuels
ity studies being conducted by the own- and for USC PC and SC CFBC technologies. These CoalFleet specifications, based
ers of three to five CoalFleet companies
that have pledged to build IGCC or other on the real-world experience of earlyadvanced coal plants. The early-deploy- deployment projects, should reduce the
time and cost for plant engineering conment project owners will benefit from the
siderably and result in plants with imknowledge, design, and operations and
maintenance experience in CoalFleet, proved performance and availability.
While IGCC is inherently very clean,
while the broader CoalFleet membership
will benefit from the rapid, real-life feed- obtaining environmental permits for an
IGCC plant is a critical-path item in the
back from the early-deployment projects.
project development process, and applicaThis symbiotic relationship will continue
as early-deployer companies select a sup- tions often must be submitted before frontend engineering is under way. The limited
plier and commit to the development of
experience of regulators with IGCC pera process design package and front-end
engineering design, followed by detailed mitting and a dearth of reference information from previous permits compound
design and construction.
As the early-deployment projects prog- the challenge. As a result, obtaining permits for a new IGCC plant can be highly
ress, CoalFleet will form teams for each
complex and pose a significant risk for
project that will translate project-specific,
nonproprietary information into a Coal- delays in plant construction. CoalFleet’s
Fleet Pre-Design Specification and a Ge- IGCC Permitting Task Working Group
neric Design Specification. The PreDesign Specifica100
Cost of CO2 sequestration
tion is essentially
Cost of CO2 capture
a generic version
80
of the project’s
feasibility study,
60
and the Generic
Design Specifica40
tion corre­sponds
to ap­proximately
the first 50% of
20
front-end
engineering design.
0
NGCC
IGCC
USC PC
Nonproprietar y
($5 NG)
costs and project
financial proformas for different
In comparisons of the 30-year levelized cost of electricity from new
orga niz ationa l
plants of similar capacity (500–600 MW), IGCC and USC PC compete
types will also be effectively with conventional natural gas–fired combined-cycle (NGCC)
derived, allowing plants when the price of natural gas reaches $5/million Btu—a level
CoalFleet partici- already exceeded today. And when the cost of capturing and
pants to see the sequestering CO2 becomes a factor, as many believe it will in the
anticipated bene- future, IGCC appears to have a clear economic advantage.
Cost of Electricity ($/MWh)
costs, and risks of building advanced coal
plants.”
To start the process, EPRI and the
CoalFleet world-class experts have assembled an Advanced Coal Technologies
Knowledge Base, the core of which presently comprises more than 50 design cases
from eight recent state-of-the-art studies
conducted by EPRI, DOE, utility companies, consultants, and technology supplier teams. Each case study details vital
characteristics in up to 450 defined fields.
CoalFleet will continue to add data as
they become available from new feasibility studies by members and from design
decisions made by companies undertaking early plant deployment projects. The
knowledge base will also include papers
from key conferences and lessons learned
from IGCC demonstration units at Cinergy Corp.’s Wabash River Generating
Station and Tampa Electric Co.’s Polk
Power Station.
“EPRI, the CoalFleet independent experts, and a CoalFleet participants’ task
working group are drawing on the knowledge base to assemble a clear and complete
User Design Basis Specification (UDBS)
for IGCC plant designers,” says Parkes.
CoalFleet’s initial version of the UDBS
will include three 600-MW bituminous
coal–fired IGCC plants, one for each of
the three commercial entrained-flow gasifiers (i.e., GE Energy, ConocoPhillips,
and Shell). For utilizing low-sulfur Powder River Basin (subbituminous) coal, the
UDBS will include an 800-MW IGCC
plant from Shell and a 600-MW transport-gasifier plant from Kellogg, Brown
& Root.
For each plant, the UDBS will estimate
availability with and without a spare gasifier and will specify three cooling options—wet tower, dry cooling, and parallel wet-dry. Also included are heat rate
targets, back-up fuel considerations, timeto-build targets, emission limits for startup and off-design operation, and expected
supplier performance guarantees. Subsequent CoalFleet UDBS documents will
cover USC PC and SC CFBC plants.
S U M M E R
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13
Two demonstration projects supported by DOE and the industry have paved the way for the
deployment of IGCC technology. Cinergy was host to a 262-MW IGCC repowering demonstration
at its Wabash River Generating Station near Terra Haute, Indiana, in 1995. Tampa Electric’s 250MW Polk County IGCC demo is a green-field unit that began operation in 1996.
is attempting to significantly reduce the
time to permit an IGCC plant through
identification of the critical technical,
regulatory, and procedural issues that
must be addressed up-front and through
the plant design and equipment selection
process. The group’s findings will guide
the development of design recommendations for enhancing and streamlining the
permitting process.
Columbus-based American Electric
Power Co. announced in 2004 that it
plans to build a large-scale, commercial
600-MW IGCC plant. The company
contracted with GE Energy and Bechtel
Corp. for a scoping study of the param­
eters of an IGCC facility at one of
three sites in Ohio, Kentucky, and West
Virginia.
“Continuing significant environmental investments in our current fleet and
building a commercial-scale IGCC plant
are the right steps going forward to ensure that we can continue to burn coal
economically while reducing our emissions,” says Michael G. Morris, AEP’s
chairman, president, and chief executive
officer. “AEP is taking significant steps to
keep coal in the picture as a low-cost, low-
14
E P R I
J O U R N A L
emissions energy source. We must be able
to rely on our vast coal resources to generate electricity if America and the world are
to continue to have growing economies.”
Adds Robert Powers, AEP’s executive
vice president for generation, “The CoalFleet initiative is important to the industry’s ability to help resolve many of the
new environmental issues and challenges
we face in a cost-effective manner. We’re
at a crossroads. After the demonstrations
of IGCC in the 1990s, we’re now working
to answer how the technology will perform at large scale and whether it can
compete as new baseload capacity. Achieving the low capital cost and low cost of
electricity demanded by today’s customers will be an exciting challenge. CoalFleet reflects the recognition by EPRI’s
membership that it’s time to make something happen and to move ahead with
advanced coal power systems.”
Meanwhile, Cincinnati-based Cinergy
Corp., under an agreement with GE Energy and Bechtel, is studying the feasibility of building a commercial 500- to
600-MW IGCC generating station at one
of several possible sites, including the 50year-old coal-fired station of its subsidiary
Public Service of Indiana at Edwards­
port, Indiana. PSI earlier was host and
cosponsor with DOE of a $417 million
IGCC repowering demonstration at PSI’s
Wabash River Generating Station near
Terre Haute. The project’s new 262-MW
IGCC plant successfully demonstrated
40% efficiency and plant availability as
high as 79% from 1995 to 1999. Akronbased FirstEnergy Corporation has also
announced interest in the development
and commercial deployment of IGCC
technology within the next several years.
And a team led by Southern Company
was selected for a DOE Clean Coal Power
Initiative (CCPI) Round 2 award to build
a 285-MW transport-gasifier IGCC plant
in Orlando, Florida.
“We face the need for additional generation in Indiana, and as the demand
for electricity increases in the future, we
will need to build more power plants,”
says James E. Rogers, Cinergy’s president,
chief executive officer, and chairman.
“Coal is our most practical, economical option. But the key to building more
coal plants will be to develop zero-emission, clean coal technologies. Our central challenge is to find ways to use an
abundant energy resource—of which our
country has a more than 250-year supply
in reserve—in an economic and environmentally clean way,” adds Rogers. “Coal
gasification has proven to be efficient,
and there is no cleaner coal generating
technology. It is critical for our country
to commercialize IGCC, from the standpoint of greater energy independence and
from that of the international balance of
payments. We need to get to work now
deploying and optimizing the current
generation of commercial IGCC so that
even more economical generations of the
technology will be available over the next
10 to 15 years.”
Linking R&D and Deployment
to Reduce Costs
CoalFleet participants believe that collaborative research, development, and
demonstration among power industry
stakeholders can both hasten the deployment of current state-of-the-art advanced
coal plants and spur the development of
technical and operational improvements.
Such advances promise to boost availability or lower heat rate and emissions in
the near term and ultimately lead to the
commercial introduction of next-generation plant designs that are approximately
20–25% lower in capital cost.
The initiative’s strategy simultaneously
addresses the RD&D needs for three
­major timeframes:
• Near-term refinements or evolutionary technologies for IGCC, USC PC,
and SC CFBC plants coming on-line
around 2010–2012—the early-deployment projects.
• Mid-term R&D requiring demonstrations that will conclude after the earliest commercial projects are built; this
work will produce technologies that
can be readily incorporated in plants
coming on-line around 2012–2015.
• Longer-term R&D on advanced concepts for IGCC, USC PC, and SC
CFBC plants—including integration
of CO2 capture systems—for plants
coming on-line after 2015–2020.
DOE is currently supporting fundamental materials research, coal plant–
related RD&D, and new coal technology
plant demonstrations through the CCPI.
FutureGen, a large IGCC demonstration
project initiative of the DOE, will involve approximately $1 billion when
fully funded. These efforts represent a
substantial contribution to the development of advanced coal systems. EPRI is
actively participating in many of these
programs to help ensure the suitability and transferability of results to users.
Technology from DOE’s RD&D programs, along with CoalFleet results and
industry RD&D, must be incorporated
and proven in both early-deployment and
next-generation units. Coordination with
relevant programs in other countries will
also help CoalFleet accelerate advanced
coal plant deployment, especially for USC
PC units.
Railroad Co. (1)
Federal Agency (1)
Federal Power Co. (1)
Eng/Proc/Const Co. (2)
IOU (15)
State Utility (2)
Muni (2)
Int'l Utility (3)
IPP (3)
Supplier (8)
Co-op (4)
The CoalFleet for Tomorrow Initiative is supported by an extremely broad range of stakeholders.
At the time of publication, 42 participants were on-board, representing more than 50% of the
coal-fired generation in the United States.
In 2005, CoalFleet is creating an industry-focused RD&D plan with projects that augment and accelerate current
RD&D activities; the initial emphasis is
on technology that could be ready for inclusion in early-deployment plants. Some
needs are well understood, and plans are
already being developed for collaborative
RD&D projects that address longer gasifier feed nozzle and refractory life and
reliability improvements for syngas-fed
combustion turbines. Other projects will
explore heat rate improvement and ­lowercost CO2 separation and capture processes. Human performance capability
enhancement projects will also be developed, including efforts involving training
simulators, instrumentation and control
systems, and operation and maintenance
guidelines. Private and public partners
will be identified to help launch high-priority projects over the next year.
Pushing Forward to a
New Generation
CoalFleet has attracted a great deal of
industry support, and for good reason.
“CoalFleet for Tomorrow is an extremely
important initiative for our energy and
environmental future, considering that
our nation generates half of its electricity
from coal, which is really the only generating fuel we have in ample, long-term
supply,” notes Barry Pulskamp, Cinergy’s
vice president for power operations. “The
CoalFleet initiative is bringing all the
players in advanced coal systems technology into the fray to reduce the cost of
these systems for producing electricity.
We’ve seen tremendous improvement in
the reliability of IGCC technology and
the resolution of many technical issues
over the past decade. Now the industry
must take advanced clean coal technologies to the next generation and further
drive costs down through plant standardization. Chevrolet has improved its V-8
engine enormously over 50 years, and the
company has produced around 100 million units. I would hope that our industry
could achieve the same degree of improvement in advanced coal systems in terms of
cost efficiency and emissions. I’m excited
about our prospects for the future.”
Background information for this article was
pro-vided by Stu Dalton (sdalton@epri.com),
Jack Parkes (jparkes@epri.com), Neville
Holt (nholt@epri.com), and Tom Wilson
(twilson@epri.com).
S U M M E R
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15
MERCURY
CONTROL
for Coal-fired
power plants
by Paul Haase
The Story in Brief
After some 15 years of study, the U.S. Environmental Protection Agency issued final rules
on March 15, 2005, for regulating mercury
emissions from coal-fired power plants. The
new ­regulations require a reduction of mercury
emissions by 70%, phased in over the coming 12 years. No commercial technologies yet
exist for fully controlling mercury emissions from
coal plants, but several approaches show good
potential in full-scale tests and some are nearing market readiness. EPRI, working closely with
DOE and the power industry, has conducted
­extensive mercury control research and developed some of the most promising technologies.
s late as the 1950s, mercury perme­­­ated American life. Parents
annu­ally administered mercurous chloride, or calomel, to children as a
laxative and dewormer. Mercury-bearing
calamine lotion soothed itches; mercurochrome sterilized wounds; mercuro-organic wonder-compounds preserved seeds
and wood. Mercury even helped smooth
the ride of luxury cars—one Studebaker
model employed some 40 pounds of it.
Although the risk of mercury vapor as a
human neurotoxin was not unknown—
the U.S. Public Health Service banned
mercury from felt-making in 1941—few
concerned themselves with mercury waste
when children sought out spilled blobs of
mercury to play with. Factories discharged
mercury directly into rivers and lakes,
hospitals and laboratories discarded broken mercury thermometers with the trash,
incinerators and power plants sent mercury skyward.
side-down. The U.S. Environmental Protection Agency (EPA) named mercury as
a potentially hazardous air pollutant in
1971, and the Safe Drinking Water Act
in 1974 established limits on mercury in
public water systems. The 1976 Resource
Conservation and Recovery Act identi­fied mercury as a hazardous material and
man­dated safe management and disposal
(in­clud­ing for emissions from combustion). Regulators have since refined and
expanded pollution laws to eliminate mer­
cury in batteries and paint, reduce emissions from municipal incinerators and
­industry, and control most other sources.
Today, domestic use of mercury has
dropped to well below one-fifth of its
1964 peak, according to EPA estimates.
The worst human health problem, discharging mercury-containing waste into
water where it can contaminate food fish,
has been virtually eliminated in the
­United States.
Mercury emissions to the air were the
last to be regulated, with initial rules
focus­­ing on two of the most obvious
­sources—medical waste incineration and
the burning of municipal waste. As a ­
Mercury Emissions (tons per year)
Quick Change for Quicksilver
By the 1960s, recognition of mercury as a
toxin and environmental danger turned
the public attitude toward mercury up-
250
200
63.56
72.76
150
49.73
40.47
100
56.73
50
0
31.78
58.21
1.6
4.9
51.05
51.25
47.91
1990
1996
1999
Utility Coal Boilers
Medical Waste Incinerators
Municipal Waste Combustors
Other (gold mines, institutional boilers, chlorine
production, hazardous waste incineration, etc.)
U.S. mercury air emissions have been substantially reduced over the last 15 years, in part through
regulation of medical waste incineration and municipal waste combustion. EPA’s Clean Air
Mercury Rule, issued earlier this year, will put limits on emissions from the nation’s 600 or so large
coal-fired power plants.
18
E P R I
J O U R N A L
result, U.S. mercury air emissions have
fallen by half since 1990, to about 115
tons per year, and continue to decline.
This progress has focused attention on a
third substantial source of mercury air
emissions: the nation’s 600 or so large
coal-fired power plants. Mercury from
these plants accounts for 45–50 tons of
domestic mercury air pollution annually.
And while the releases have remained
steady at this level for the past 15 years, as
other mercury emissions have fallen, coal
plants have come to represent a greater
and greater fraction—now about 40% —
of total domestic emissions. In a global
accounting, mercury emissions from U.S.
coal plants represent less than 1% of natural and human-caused sources.
The Clean Air Mercury Rule
EPA began studying coal plants as the last
significant source of mercury emissions
in 1997 and, after some controversy (see
sidebar, p. 24), formally issued its Clean
Air Mercury Rule, or CAMR, to regu­late
coal plant emissions on March 15, 2005.
This two-phased rule creates performance
standards and establishes permanent, declining caps on mercury emissions from
coal plants. The Clean Air Mercury Rule
marks the first time EPA has regulated
mercury emissions from coal-fired power
plants and makes the United States the
first country in the world to regulate
these emissions.
The mercury rule is intended to work
in tandem with EPA’s new Clean Air In­ter­
state Rule, or CAIR, which tightens ex­ist­
ing regulations on two other coal plant
emis­sions: sulfur dioxide (SO2), which con­
tributes to acid rain and fine particulates,
and nitrogen oxides (NOx), a precursor of
ozone (sometimes referred to as smog) and
also of fine particulates. The aim is that by
2018, these two rules will reduce coal plant
emissions of mercury by about 70%, to 15
tons per year nationwide. Reductions will
be achieved through a market-based “capand-trade” pro­gram similar to that of EPA’s
highly successful Acid Rain Program,
which in the 1990s delivered its environ-
Polishing Filter
(TOXECONTM)
Coal
Additives
Sorbent Injection
Combustion
Modifications
Scrubber
Coal Cleaning
Coal Blending
ESP/Fabric
Filter
Boiler
Stack
FGD
Additives
SCR
Catalysts
Fixed Adsorption Structures
A number of approaches are being investigated for controlling mercury emissions from coal-fired power plants. Potentially beneficial modifications
of the fuel or combustion process include coal cleaning, coal blending, and control of the mixing of air and coal during combustion. Options
to increase the removal of mercury by scrubbers, which are already on the system to control SO2 emissions, include adding an SCR (which also
reduces NOx emissions) or catalysts and additives designed specifically to convert the mercury to a scrubbable form. Finally, several mercury-specific
approaches are being developed—injection of activated carbon or other sorbent material into the flue gas, sorbent-based polishing filters, and fixed
adsorption structures.
mental improvements faster and much
more inexpensively than anticipated.
Under the cap-and-trade program for
mercury, EPA will assign individual states
(and two Native American tribes with
coal-fired power plants on their lands) an
emissions budget for mercury. Each state
will determine how to regulate its coal
plants to meet this emissions budget.
During the phase-in period, plants that
meet emissions limits ahead of time can
bank these credits for use later or can sell
them to those that will not be able to meet
their limits on time. After the 2010 Phase
1 compliance date and the 2018 Phase 2
compliance date, companies whose plants
in aggregate control mercury emissions
below their allocated limit will be able to
sell the “over-control” amount to companies whose plants cannot achieve their
­a llocated limits cost effectively.
The Capture Challenge
Now that EPA has ruled, coal plant owners and operators will need the means to
better capture mercury emissions. Some
improvements can be achieved by modifying existing SO2 or NOx control devices,
but new approaches will be required to
meet the final 2018 emission limits. As
yet, no technology designed specifically
to control mercury in coal plants is in use
anywhere in the world, or has even under­
gone long-term testing.
To develop and demonstrate such technologies, EPRI is working with the U.S.
power industry and government organi­
za­tions in a broad program of research
and field testing at power plants. The
large-scale mercury field testing in the
United States was made feasible through
signifi­cant funding and technical management by the U.S. DOE’s National
Energy Technology Laboratory (NETL).
Important col­laborators are the host sites,
the developers of the control technologies
themselves, and the engineering firms
conducting the tests. The overall effort
builds on 15 years of EPRI mercury control research.
This important work could not be done
without the contributions of the many
power companies that offer their plants
for field testing. “With federal regula-
S U M M E R
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19
The DOE-NETL field test program, which
benefits from 15 years of EPRI mercury
research, is exploring the effectiveness of a
dozen mercury control strategies at over 30
utility plants. The extensive test program is
scheduled to continue through 2007.
(Photos courtesy URS Corp.)
tion now in place, full-scale testing at the
power plant is a critical step in the development of potential technologies,” says
EPRI President and CEO Steve Specker.
“We cannot simulate these conditions
in the laboratory and need to determine
whether performance in the field can be
sustained over a period of time without
interfering with the plant’s operation.”
The commitment of the field-test utilities
20
E P R I
J O U R N A L
is of tremendous value, considering that a
typical coal plant generates tens of thousands of dollars worth of electricity each
hour—electricity and revenue that are
lost if the plant is shut down to install or
tend experimental equipment.
Most emission control strategies for
mercury focus on boosting the mercurycapture effectiveness of the standard pollution control equipment already installed
at existing coal-fired power plants. This
equipment includes flue gas catalysts to
control NOx, scrubbers and spray dryers
to capture SO2, and particulate filters to
catch fly ash. These existing technologies capture about 35% of the mercury
in flue gases, on average, but performance
varies widely from plant to plant. Of the
approximately 75 tons of mercury found
in the tens of millions of tons of coal
delivered to power plants each year, about
25–30 tons are captured in existing pollution controls and 45–50 tons are emitted
to the air.
Key to capturing emissions is the chem­
ical form of the mercury—elemental or
ionic—as it passes through each pollution
control device. Ionic mercury, which is
soluble in water, is absorbed in scrubbers,
whereas elemental mercury is not. Thus,
the mercury-control challenge in a coal
plant is primarily one of chemistry. For
plants with existing or impending SO2
controls, the objective is to increase the
proportion of ionic mercury—either during combustion of the coal or in the flue
gas itself—by some kind of oxidation process. Those without SO2 controls may need
to install mercury-specific technology.
The choice is neither simple nor obvious. Chemistry and economics dictate
that most coal plants will employ one
mercury control approach rather than a
combination, and the choice must be determined plant by plant because of the
wide difference in coal plant designs, the
pollution equipment they have, and the
coal types they burn. “For any given regulation, we must have options for all the
combinations of coals and existing air
pollution controls used by the industry,”
says George Offen, EPRI’s technical
­executive for air emissions. “It’s no ‘onesize-fits-all’ situation.”
Modifying Coal and
Combustion
Mercury control starts with the source,
coal. This presents the first difficulty, because coal is a sedimentary rock that has
no fixed composition. In coal, as in many
similar sediments, mercury occurs as a
trace element at about one part per million. Although coals come in a great variety—the chemistry and characteris­tics
varying with the amount of heat and pressure a coal has experienced over its long
history—most U.S. power plants burn one
of two broad types, according to which is
regionally available. In the East, plants
generally fire harder bituminous coal,
Sunflower Electric’s Holcomb Station near Garden City, Kansas, was host to a full-scale field test
of sorbent injection for mercury capture under the DOE-NETL program. Conventional sorbents
injected into the flue gas duct (far left) before the plant’s spray dryer unit achieved only modest
results in removing mercury. However, use of a new, chemically enhanced sorbent removed 90%
of the mercury at low-to-moderate injection rates. The sorbent is collected by the plant’s fabric
filter, and the cleaned flue gas exits the stack at right. (Photo courtesy ADA-ES)
and in the West, softer subbituminous or
lignite coals are the typical choice. The
behavior of these coal types varies significantly with regard to mercury emissions:
most—more than 60% —of the mercury
released from the combustion of eastern
coal is in the soluble and more easily captured ionic form, whereas only 20–30%
of mercury released from western coal is
ionic. Thus, even though eastern coals
typically contain one-third more mercury
than western types, plants firing western
coal generally will require more aggressive
approaches to control mercury emissions.
Precombustion cleaning increases the
mercury difference between coal types,
because eastern coal can be cleaned prior
to use whereas western types generally
cannot. Cleaning removes noncombustible materials and, for eastern coals,
­reduces mercury content by about onethird on average. For western coals, various dewatering treatments have been ex-
plored to improve combustion properties;
such dewatering appears to also remove
mercury—up to 70% in tests—and may
become commercial in the future.
Cleaned or not, once coal reaches a
power plant, several mercury control strat­
e­gies are possible. First, the combustion
process can be modified to increase the
yield of unburned carbon in the fly ash,
which can adsorb mercury emissions;
the additional carbon may also increase
the percentage of ionic mercury. These
changes may be accomplished by staging
the flow of air or coal in the boiler or by
adding halide salts or other treatments to
the coal or directly in the boiler.
“Several of our research projects have
shown that adding a little halogen to
promote oxidation significantly improves
short-term mercury capture on western
coals,” says Ramsay Chang, EPRI’s technical leader for air emissions. DOE-NETL
is following up on these results in 2005
S U M M E R
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21
by cofunding longer-term tests of halogen
additives at two power plants burning
western coals.
Increased yield of ionic mercury or
adsorbent carbon ash can also be accomplished by blending different types of coal.
In short-term tests at Sunflower Electric’s
360-MW Holcomb Station, located near
Garden City, Kansas, EPRI researchers
found that mixing modest amounts of
bituminous coal with the subbituminous
Powder River Basin (PRB) coal fired at
the plant reduced mercury emissions by
up to 80% without any other changes.
“The emissions control equipment at
Sunflower’s Holcomb Station is typical
of many power plants in the West,” says
EPRI’s Specker. “It has exactly the same
configuration as most of the new plants
being planned that will burn PRB coal.
This makes the results particularly significant.” Indeed, EPRI recently honored
Sunflower Electric with its 2005 Technology Achievement Award for Rural Electric Cooperatives for hosting this work.
Tests at Holcomb Station are part of
EPRI’s work with DOE-NETL to perform extensive longer-term mercury control technology testing for coal plants in
the 2004–2007 timeframe. EPRI is coordinating with the power industry to shape
the design and content of the DOE-NETL
tests. It’s a big job: in addition to government agencies and host Sunflower Electric,
the Holcomb test alone involved ADA-ES,
Inc., NORIT Americas, Arch Coal, Western Fuels Association, Kansas City Board
of Public Utilities, Westar Energy, Empire
District Electric Company, Nebraska Public Power District, Kansas City Power and
Light, Tri-State Generation & Transmission, Missouri Basin Power Project, Wisconsin Public Service, Associated Electric,
Southern Minnesota Municipal Power
Agency, the City of Sikeston, TransAlta
Utilities, and TransAlta Energy.
Co-Benefit Approaches
The mercury-control potential of com­
bustion modifications at many plants may
be limited by the chemistry governing
22
E P R I
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plant efficiencies, by boiler corrosion
from ­halide salts, or by the economics of
coal transport. But “co-benefit” modifications are possible that can boost mercury
capture in equipment already installed to
control SO2 and NOx emissions.
SO2 is captured by routing flue gas
through large liquid-filter flue gas desulfurization (FGD) scrubbers or through
spray dryers that work with an injected
slurry of a calcium compound. Such SO2
controls capture nearly all of the ionic
mercury emissions but almost no elemental mercury. Consequently, mercury control based on SO2 controls and combustion modifications work best at plants
firing eastern coal. FGD additives are
being developed to retain the mercury in
the scrubber liquid once it is captured and
prevent its re-release in elemental form,
which some experiments show may be a
concern.
NOx in flue gas is usually controlled
using selective catalytic reduction (SCR)
approaches. These catalysts also convert
a large fraction of elemental mercury in
flue gas to soluble ionic mercury, which
can then be captured in FGD scrubbers.
Mercury-specific catalysts can be used
at plants lacking SCR equipment and at
those firing western fuels whose mercury
emissions are relatively unaffected by
SCR treatment. EPRI and DOE-NETL
found catalysts to convert 65–90% of elemental mercury to ionic mercury in the
gas streams at a Great River Energy plant
and a City Public Service of San Antonio
plant, both firing soft western coal; further pilot-scale tests are planned for western and eastern coals in 2005 and 2006.
As more and more SO2 and NOx controls are installed to comply with the new
Clean Air Interstate Rule, mercury emissions are expected to fall before the cuts
required by the Clean Air Mercury Rule
phase in. This multi-pollutant co-benefit
approach is central to EPA’s plan to reduce mercury from power plants. Indeed,
a number of vendors are developing integrated environmental control technologies that simultaneously remove mercury,
NOx, SO2, and other pollutants, as an eco­
nomical option for plants installing controls for multiple pollutants at once.
Mercury-Specific Options
Many plants without SO2 controls will
still need to deal with their mercury out­
put, and even those that do have scrubbers in place may need additional mercury
controls to meet the final EPA cap. Today’s leading mercury-specific approach,
adapted from technology devised for solid
waste incinerators, is the injection of finepowder sorbent material—typically activated carbon—into the flue gas flowing
from the boiler. A sorbent works by attracting and binding mercury to its surface; the sorbent and mercury together
are then captured by a downstream particulate filter such as the electrostatic precipitators (ESPs) fitted at most plants to
control fly ash. Short-term tests in 2002
and 2003 indicated high effectiveness—
80–90% mercury capture for eastern
coals and 60–70% for western coals—but
also raised questions of sorbent cost and
long-term performance.
To explore possible cost reductions,
EPRI and DOE-NETL are cofunding
stud­ies of various sorbents. In a fourweek test as part of the larger program at
Sunflower Electric, a new chemically
­enhanced sor­bent removed more than
90% of the ­ mercury produced at Holcomb Station relatively inexpensively.
With­out this sor­bent, the plant’s standard
emission controls captured almost no
­mer­cury. A combination of conventional
activated carbon sorbent and a propri­etary additive also proved potentially
cost-effective at Holcomb.
“From the perspective of a power producer, this has been a very important test
program, and we are quite pleased with the
results,” said Wayne Penrod, senior manager of environment and production planning at Sunflower Electric. “We were able
to determine that there are perhaps three
methods from which we can choose in
deciding how Sunflower will comply with
future mercury reduction requirements.”
Long-term performance of sorbents will
be studied in full-scale power plant tests
later in 2005 and in 2006.
EPRI research is also addressing a major problem with using sorbents to control
mercury emissions: contamination of fly
ash. Currently, a significant amount of
fly ash from coal plants is sold to cement
makers for use as a concrete additive.
This market benefits the environment
by reducing CO2 emissions from cement
plants and minimizing landfill. However,
conventional sorbents, which are captured
along with fly ash, change the properties
of the ash and render it unsuitable for use
in concrete. Power plant operators who
choose sorbents not only stand to lose
profitable ash sales, they face large new
costs for disposing of millions of tons of
ash waste each year.
New TOXECON™ technology pat­
ented by EPRI avoids this contamination
by separating the capture of fly ash from
the collection of mercury-containing
sorbent. The process captures mercury
as well as or better than conventional
sorbent ­ approaches, as demonstrated in
2001–2002 full-scale tests at Alabama
Power’s Plant Gaston and in long-term
tests conducted in 2004.
TOXECON works by delaying sorbent
injection into flue gas until after the fly
ash has been collected in a plant’s primary
particulate filter; the mercury-laden sorbent is then captured in a secondary filter, or baghouse, installed further downstream. In addition to preserving fly ash
for concrete sales, this process requires less
sorbent to achieve high levels of mercury
capture because the sorbent has greater
exposure to mercury in the ash-free gas
stream. Consequently, TOXECON is
attrac­tive for any power plant that needs
to retain ash sales, and it earned runnerup status in the environmental category
of the Wall Street Journal’s 2004 Technology Innovation Awards.
“We’ve now licensed five companies
to use the system, and We Energies has
purchased the technology to install in its
Presque Isle Station in upper Michigan,”
Deposition
(µg/m2/yr)
0 to 5
5 to 10
10 to 15
15 to 20
20 to 25
25 to 50
50 to 75
75 to 100
100 to 150
150 to 250
250 to 383
EPRI global and regional models of mercury deposition (considering all
global emission sources) show the expected results of the new Clean Air
Mercury Rule. Comparisons of deposition for (a) 2004 and (b) 2020
indicate that the cap-and-trade approach will indeed reduce deposition
in the East. However, because mercury emissions from outside the United
States are so much higher than domestic emissions, even if U.S. coal-plant
contributions (about 40% of U.S. emissions) were completely eliminated
(c), overall U.S. deposition would drop by only 9%.
S U M M E R
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23
Hot Spots, or What Goes Up Must
Come Down—Eventually
The Clean Air Mercury Rule regulates emissions, but the goal is not
to improve air quality per se—the highest concentrations of mercury
vapor in domestic air run less than one-thirtieth the lowest EPA risk
level—but rather to control mercury in fish. The ultimate goal is to
protect women and their unborn children by minimizing mercury
concentrations in fish that may be eaten by pregnant mothers. Misunderstandings about how coal plant mercury emissions connect to
mercury in fish and humans are the sources of much of the controversy over the recent EPA rulemaking.
Most of the major U.S. sources of mercury entering the environment
position levels cannot be known or measured everywhere across the
country, rulemaking was informed extensively by computer modeling.
Both EPA and EPRI employed state-of-the-art—although slightly different—model sets, both of which are well regarded and give similar
results. Each shows that well more than half of the mercury deposited
in the United States comes from non-domestic sources (mostly Asia) and
that deposition at only a few U.S. locations is dominated by domestic
coal plant emissions.
have been controlled by various regulations over the past decades. The
Modelers found—and ground studies confirm—that rather than
major human health concern about mercury pollution is potential neuro-
falling to earth near emission sources, most mercury from coal plants
logical damage in fetuses that may result when pregnant women consume
is dispersed throughout the global atmosphere and resides there for
certain fish. Bacteria in water transform a fraction of the mercury that enters
up to a year. Eventually the mercury comes down to earth. Because
a lake, a river, or the ocean—whether from human or natural sources—
mercury emissions from non-domestic sources are so much higher than
into a compound called monomethylmercury, CH3Hg , usually referred to
those from domestic sources, even if all U.S. coal-plant mercury air
+
simply as “methylmercury.” Fish pick up methylmercury through their food
pollution were eliminated, overall U.S. mercury deposition would drop
chain and, because it degrades only slowly, larger fish accumulate more
by only 9%.
and more methylmercury from each smaller fish they eat. Through such bio-
Accordingly, EPRI modeled different mercury control proposals to
magnification, methylmercury concentrations can reach significant levels in
identify which would provide the maximum benefit at reasonable cost.
top predator fish such as pike, walleye, and swordfish.
A proposal to regulate mercury emissions at every plant to a speci-
Although the level at which methylmercury in fish is risky to fetuses
fied emission limit under the Clean Air Act’s Maximum Achievable
is unknown—no explicit cases have been recorded and studies are
Control Technology (MACT) provisions was found to reduce average
obviously impractical—the federal Centers for Disease Control and Pre-
domestic mercury deposition by about 5% at a total cost of about
vention has extrapolated from other data to conclude that, at any time,
$10 billion (net present value). By contrast, the cap-and-trade ap-
one in six American women of childbearing age has mercury levels in
proach, as selected, cuts mercury deposition by 7% at an expected
her blood that might put a fetus at risk. At least 43 states issued mercury
cost of $2 billion. EPA modeled the cap-and-trade approach as well,
warnings for lakes and rivers at different times in 2002.
with similar results.
says EPRI’s Offen. The Presque Isle instal­
lation, expected to come on-line later in
2005, is cofunded under DOE’s Clean
Coal Power Initiative—a program that
encourages the use of new technologies by
sharing their cost with private industry.
TOXECON is not without ­competition.
New alternative sorbents are being formulated that may not impact fly ash. In early
tests these alternatives appear less effective
than conventional sorbents, but they may
prove less costly than TOXECON. In the
24
EPA devised the Clean Air Mercury Rule to reduce the impact of
mercury on children as much as is practicable. Because mercury de-
E P R I
J O U R N A L
meantime, EPRI is testing a lower-cost
variant technology called TOXECON II
that avoids the need for a polishing (second) baghouse. In this variant, sorbent
injection occurs near the back end of the
primary filter, just ahead of the last one
or two collection fields but after most of
the fly ash has been collected. The final
fields then collect the mercury-bearing
sorbent separately from the ash, but without a baghouse. Early tests indicate TOXECON II captures 50–70% of mercury
in flue gas from western coal. DOE plans
longer-terms tests of alternative sorbents
and TOXECON II in 2005 and 2006.
The last chance to capture coal plant
mercury occurs at the exhaust stack. Here
fixed adsorption structures—plates or
honey­combs coated with mercury sorbents such as gold or metallized solid
polymer electrolytes—can collect much
of the mercury remaining in flue gas after
other treatments. These technologies,
such as EPRI’s Mercury Capture by
meet future mercury emission requirements),
emissions nationally would still decline, as
Volatilization
an overall cap on emissions would need to
be reached. EPRI modeling finds that none of
the 600 power plants with mercury emissions
over 100 pounds per year in 2004 would
actually increase their emissions. Emissions
Hg(ll)
deposition
and runoff
u
Red
ction
Hg(0)
Hg(II)
Predatory
fish
at only six plants would remain unchanged,
D e me
thyla
tion
Small
fish
PhytoZooplankton plankton
and two of these plants already meet the new
CH3Hg
mercury emission requirements. Additionally,
the cost of purchasing credits still motivates
power plants to reduce emissions as much as
possible. Thus, when the new national cap
on mercury emissions is implemented by EPA
Sedimentation
and the states, a movement away from higher deposition of mercury to waterways would
be expected.
Methylation
EPRI computer analyses of the entire United States show that areas of high mercury
Mercury entering lakes—by direct deposition from the atmosphere or via terrestrial runoff—
typically includes elemental mercury, Hg(0), and oxidized mercury, Hg(II). An organic form,
monomethylmercury, CH3Hg, may be produced when anaerobic bacteria in the water and
sediments methylate oxidized mercury through a metabolic process. Plankton and other organisms
bioaccumulate the CH3Hg, passing it up the food chain to fish, where it may concentrate to levels
of concern for human health.
deposition are not dominated by electric utility mercury emissions (the largest area, Chesapeake Bay, results from a municipal incinerator). Indeed, EPA analyses show that growth
in emissions from domestic non-utility sources
will continue to drive deposition changes
even following the new power plant rule.
With the cap-and-trade Clean Air Mercury Rule, EPRI finds that the
Finally, to address the global nature of mercury control, the United
average risk of excess exposure to coal plant mercury for Americans will
States leads an effort in the United Nations Environment Programme
fall by a factor of 15, from about a 0.6% chance to 0.04%. Reductions
(UNEP) to establish partnerships that would help developing countries
will vary across the country, with the smallest changes in low-­deposition
reduce mercury emissions. The idea is to leverage technology transfer,
western states and the greatest reduction in higher-deposition West
resources, expertise, and information exchange to cut mercury use and
Virginia. No “hot spots,” with increased mercury deposition, will be
emissions. This effort accelerates the work of the UNEP mercury pro-
created. Although some plants may delay or avoid mercury reductions
gram proposed by the United States at the 2003 UNEP Governing
(because of the availability of emissions credits or because they already
Council meeting.
­ dsorption Process (MerCAP™), are
A
mostly in early development.
The Final Cost of Control
Today there is no question that coal plant
mercury emissions can be captured, but
the long-term effectiveness of the different control strategies remains uncertain.
Extensive field tests involving U.S. government organizations, EPRI, and the
power industry are expected to confirm
by the end of the decade that appropriate
approaches can be confidently deployed
to the nation’s coal plants to meet the
phased emission reductions required by
EPA’s mercury rules.
The final cost of the Clean Air ­Mercury
Rule remains largely unknown as well,
but EPA projects that the expense to the
nation will run some $2 billion (net present value). For the residential con­sumer,
EPRI estimates this cost will add 0.1–
0.3¢/kWh to the 6–8¢/kWh typically
paid in the Midwest—an increase of
about 1.5–3.5%. Better estimates await
the conclusion of the ongoing power plant
test program. “If the results we get at the
end of these field tests are consistent with
our process understanding, we’ll be in a
good position,” says Offen. “If not, we
have more work ahead of us.”
Background information for this article was
provided by Leonard Levin (llevin@epri.com),
George Offen (goffin@epri.com), and Ramsay
Chang (rchang@epri.com).
S U M M E R
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25
by John Douglas
The Story
in Brief
The rise of terrorism
in the modern world
necessitates a closer
look at the vulnerability of the power grid
to physical and cyber
assaults. A new,
industrywide initiative
focuses on protecting electric power
systems from hackers
and worse.
B
ecause electricity drives virtually
all of the nation’s critical infrastructures—from telecommunications to waterworks—the electric power
system presents an inviting target for
international terrorists. A coordinated attack on major power plants or substations
could trigger a cascading blackout with
major social and economic impacts. Depending on the extent and success of such
an attack, daily life and business could be
disrupted for several days across a wide
area of the country, and a complete return
to normalcy could take months to years.
Especially worrisome in a time of increasing industry dependence on the Internet is the fact that a devastating attack
need not be directly physical: The perpetrators could remain anonymous and remote, achieving their goals by disrupting
a utility’s computer network or power system controls. A successful cyber attack, for
example, could potentially allow a terrorist to destroy equipment by sending false
control signals or by disabling electricity
grid protective relays. Every day, a typical
large electric utility must fight off hundreds or even thousands of cyber intrusions that appear to originate with hackers
trying to disrupt normal business, obtain
sensitive data, or exert control over parts
of the grid.
Most utilities, of course, have already
en­hanced their efforts to protect both phys­
ical facilities and computer networks. The
fact that virtually all of the illegal ­ entry
attempts so far have failed indicates the
effectiveness of these security measures.
“Utilities throughout North America have
made significant strides to implement cyber and physical security,” says Luther
Tai, senior vice president, central services,
Consolidated Edison Co. “While these
have greatly reduced the vulnerabilities,
there is more that can be done through
the research and development work that is
now under way at EPRI.”
Part of the problem is that, with electric power networks so tightly interconnected, a significant security breach anywhere on the system can have an effect
28
E P R I
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on the system as a whole. Since there are
many different types of utilities in the
United States, each at a different level of
cyber preparedness, there is a compelling
incentive to improve the coordination of
security precautions taken by all utilities.
Utility decision makers face a num­ber of challenges in this area. The broad
scope of the security issue has led to development of multiple and sometimes over­
lapping require­ments from various govern­
ment agencies. At the same time, util­ity
efforts to increase security are often
­constrained by limited access to useful
­information produced by these agencies
and others, either because of the highly
clas­sified ­ nature of the data or because
the data are distributed across multiple
­locations. As a result, utility executives
have often been forced to make securityrelated decisions on the basis of sparse,
uncertain, or anecdotal information. A
further challenge for electric utilities involves internal communications—how to
effectively communicate security weaknesses identified by utility operations,
planning, and engineering personnel to
higher-level ­management.
Since 2001, a number of individual util­
ities have pioneered important cyber security efforts, each producing valuable
results. However, a lack of effective technology transfer and broad industry support has limited the effectiveness of these
results for the industry as a whole. ­Because
security is only as strong as the “weakest
link” in the chain of interconnected infor­
mation and communication systems that
utilities use, increased industry support,
participation, and successful implementation of new security tools are crucial for
effective industrywide cyber security.
In order to help provide the needed
coordination and establish a unified response to cyber threats, EPRI and other
leading industry organizations have
formed the PowerSec Initiative. In addition, important new results are emerging
from EPRI’s own long-standing R&D
work on electricity infrastructure security
as a whole.
Early Efforts to
Enhance Security
EPRI was leading an industrywide effort
to reinforce U.S. power infrastructure ­
s­ecurity well before September 11, 2001.
But as with most of the nation’s protection and emergency response programs,
the ter­rorist attacks sparked a funda­men­tal rethinking, expansion, and refo­
cusing of utility security efforts. While
­earlier ­ con­cerns largly centered on the
­effects of natural disasters, system control
anom­alies, and small-scale vandalism,
the twenty-first-century equation clearly
must include protection against calculated assaults designed to disrupt American life and commerce on a large scale.
EPRI’s Infrastructure Security Initiative
(ISI) was launched in response to these
challenges and was designed to develop
both prevention coun­ter­measures and
­enhanced recovery capabilities.
As part of the work to provide utilities
with immediately useful countermeasures, ISI is documenting lessons learned
from actual terrorist attacks and other
cata­strophic events at utilities around the
world for use by ISI participants. One of
the highlights of this effort came in 2004
with the receipt of a draft report from
­Israel Electric Corporation on best practices they have developed to defend their
grid against terrorist attacks. The counter­
mea­sures project is also providing utilities
with information on new ways to protect
their physical facilities, including a covert
detection system that uses a magnetic
field to identify potential intruders by
size, speed, and electrical conductivity.
Another system uses artificial intelligence technology to automatically analyze the stream­ing video from cameras in
remote locations to detect, for example,
whether an intruder has dropped a suspicious object.
Among potential infrastructure targets
attractive to terrorists, high-voltage transformers represent a critical vulnerability.
These transformers cost several million
dollars each and usually take one to two
years to procure, build, and install. In
r­ esponse to this threat, ISI came up with
the concept and developed preliminary
designs for a new type of transformer that
can be easily stored, transported, and installed for emergency use. An important
milestone in development of this socalled recovery transformer was achieved
in 2004 with completion of preliminary
designs for two units, rated at 500 kV and
345 kV. Both can be transported by truck,
rail, or military cargo plane, and once
all parts are available on site, they can be
installed in about 48 hours.
The design studies for the recovery
transformers indicate that they will be
about 30% lighter and smaller than
conventional units, have an efficiency of
99%, and have an expected life of about
35 years. EPRI is currently working with
the Department of Homeland Security
(DHS) seeking sponsorship for the production of prototypes for these transformers. EPRI would provide funding through
ISI for the factory testing efforts to ensure
that electric utility short-circuit criteria
and other critical performance requirements are met.
In addition, ISI is in the process of developing emergency recovery plans for
substations that have been knocked out
by a terrorist attack or other devastating
event. These plans identify methods that
utilities can use to assess which equipment is still salvageable, to identify the
need and availability of spare parts, and
to attempt to “harden” key sites against
possible attack.
Emergency communications technologies are also being evaluated by ISI in
order to recommend the best alternatives
for use in case of emergency. The aim is
to provide utilities with secure ways of
communicating with each other and with
emergency services after a successful,
multi-regional terrorist attack. This work
is being coordinated with related projects
being carried out by government agencies
and in other countries. In particular, the
use of satellite phones—which support
both voice and data communication—is
being explored.
Dealing With Cyber
Vulnerability
In this age of ubiquitous digitization, phys­­
ical attacks are far from the only concern.
The known successes of cyber attacks on a
surprising variety of industries offer chilling testimony to the need for countermeasures against computer-based intrusions.
While physical assaults—be they facility break-ins, weapon attacks, or bomb
explosions—are certainly frightening pos­
si­bilities, cyber attacks have the potential
to be every bit as destructive and carry the
insidious added threats of stealth and longdistance control. “If a cyber terrorist is able
to get through a company’s firewall and
other protection systems, it doesn’t matter
if he’s on the other side of the world,”
points out technical executive Robert
Schainker, who manages EPRI’s security
work. “If he’s linked in through the Internet—which is available virtually everywhere—and he penetrates the pro­tec­tions
to your operational systems he may as well
be sitting in your control room.”
Indeed, the incredible power and flexibility of the Internet has made cyberspace
part of the global battlefield, and several
nations have incorporated explicit plans
for attacking information systems into
their military preparations. Russia, for example, has documented successes in cyber
attacks against key Chechen web sites. India and Pakistan have pursued competing
preparations for electronic warfare. China
has formulated an official cyber warfare
doctrine, and North Korea has experimented with offensive cyber technologies.
Terrorist organizations in the Middle East
have shown increasing sophistication in
the use of information technologies and
have made no secret of their intent to
attack critical American infrastructures.
The U.S. government has long been
concerned over the wide-ranging effects
that computer-based attacks could have
on the nation’s key infrastructures. After
the Morris computer worm brought 10%
of the country’s Internet systems to a
standstill in 1988, the Defense Advanced
Modern-day security threats can be both physical and cyber-based. An intruder could destroy
a substation transformer with a bomb or by setting a fire, but a computer hacker could
accomplish the same end by sending the transformer overload signals, causing it to rapidly
overheat and explode.
S U M M E R
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29
While utilities go to great lengths to protect their critical facilities from cyber intrusion, their connections with third-party vendors can be an
unrecognized weak spot. Hackers stopped by strong firewall systems protecting the control room, for example, may be able to make it in through
weaker, standard security measures protecting vendors that provide procurement or billing services. Once in the “back door,” the intruder may be
able to move to a utility’s grid operation and control systems.
­ esearch Projects Agency (DARPA) set
R
up the Computer Emergency Response
Team (CERT) Coordination Center at
Carnegie Mellon University to ­ monitor
cyber threats and respond to serious security incidents. According to CERT,
keeping ahead of the trouble is no easy
task: “Along with the rapid increase in the
size of the Internet and its use for critical functions, there have been progressive
changes in intruder techniques, increased
amounts of damage, increased difficulty
in detecting an attack, and increased difficulty in catching the attackers.”
Earlier this year, DHS set up the Process Control Systems Forum (PCSF) to
focus specifically on threats to the comput­
erized automated control systems that underlie operation of most of the country’s
critical infrastructures, including the elec­
tric power grid. The PCSF will leverage
security knowledge currently ­ dispersed
among different infrastructures and stim-
30
E P R I
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ulate cross-functional discussions between
those responsible for information technology and operations. EPRI is co­ordinating
with the PCSF to ensure that the utility
industry’s security concerns and solutions
are shared on a confidential basis.
Technologically, utility industry restructuring has created several unforeseen
effects that increase this vulnerability.
Power companies are now much more interconnected than previously, which not
only provides more points of entry for
an attacker but also means that potential
damage may be more widespread. Open
(as opposed to proprietary) operating
systems and communications protocols
were successfully designed to improve
ease of use, but they may have made the
task of an intruder easier as well. And remote access systems, such as those used
to monitor field data and revise set points
for relays, may have opened new portals
for intrusion.
Changing business practices may also
inadvertently open new opportunities for
cyber intrusion. For example, an increasing number of businesses—including util­
ity companies—are turning to third-party
vendors to provide day-to-day admin­is­tra­
tive or service functions such as payroll,
accounting, and maintenance. As a result,
a power plant’s operating control sys­tem
may have direct communication links to
a vendor-managed purchase/selling function, such as procurement or billing. But
the vendor’s computer system may not be
as strongly protected from the outside
world as the utility’s heavily firewalled
control room, providing an easier point
of entry for hackers or computer ­viruses.
After gaining access to the utility through
this “back door,” the intruder may be able
to move to more critical areas of the plant,
unbeknownst to the utility company.
These and other emerging concerns
prompted EPRI to add computer-based
threats to its portfolio of security R&D.
EPRI’s focus on cyber security had its beginnings in the development of the first
utility open-systems architecture—the
Utility Communications Architecture
(UCA), used to share data between various computer systems in a company—and
was strengthened after the highly successful program to prepare utility computer
systems and equipment for the Y2K transition. Growing concern over the possibility of computer-based security breaches
led to development of EPRI’s Energy
Information Security (EIS) program in
2003. EIS was designed to provide tools
that individual utilities could use to enhance their own security programs, including cyber security awareness training,
information sharing, approaches to assessing control system vulnerability, and risk
management protocols.
The EIS program has already produced
valuable results. When vulnerabilities were
discovered in standard communications
protocols, such as those specified in UCA,
EIS researchers developed enhancements
designed to increase security. Early exploratory work has also been conducted
on fast encryption and instruction detection technologies to protect data and control systems. Publication of the Security
Vulnerability Self-Assessment Guideline for
the Electric Utility Industry (1001639)
enabled companies to conduct their own
risk analyses, while the Guidelines for
Detecting and Mitigating Cyber Attacks
on Electric Power Companies (1008396)
provided basic procedures for enhancing
network security.
PowerSec: A Coordinated
Approach
Much progress has been made through
EPRI’s ISI and EIS programs. But considering the complexity of the nation’s
power infrastructure, the ever-increasing
capabilities of cyber attackers, and the diverse nature of current security efforts, a
more comprehensive, highly coordinated
effort is clearly required. In response—
and in cooperation with several indus-
try organizations and the EPRI Board
of ­ Directors—EPRI drafted a proposal
for an industrywide program, identified
ongoing security work at various industry and government organizations, and
obtained feedback from more than 60
utilities, representing all segments of the
electric power industry. As a result, an alliance has been formed to create the PowerSec Initiative, which initially will bring
together EPRI staff, a variety of industry
organizations, and several industry experts to address the cyber threat issue.
By examining threats, vulnerabilities,
and potential consequences, the PowerSec
Initiative will evaluate the industry’s current cyber attack readiness, identify gaps
in this readiness, and specify existing best
practices for filling these gaps. In some
cases, even current best practices will not
be sufficient to handle emerging attack
techniques; the initiative will therefore also
identify vulnerabilities that require new
so­­lutions and specify what R&D work is
needed to develop and test these solutions.
One important goal of PowerSec is to
consolidate and leverage ongoing and
completed cyber security work from utilities, government, regulatory agencies,
and others. Appropriate information on
best practices will be disseminated to the
industry using methods consistent with
the safeguard of confidential or classified
information. In addition to integrating
and sharing disparate information, the
initiative will serve as a model of how the
utility industry, regulators, and government can work together to solve complex
security problems.
“EPRI has long been a leader in building
security awareness in the electric power
industry,” says Tom Kropp, EPRI project
manager for electric power critical infrastructure protection. “Now the information and products we have developed over
the years can help form the foundation of
a coordinated, industrywide effort.”
Early Goals
The PowerSec Initiative will focus first
on electric utility supervisory control and
data acquisition (SCADA) systems and
energy management systems (EMS), both
of which have been identified by experts
as critical systems to secure. Identifying
and filling existing security gaps in communication and control systems will make
it more difficult for potential intruders to
gain access and cause damage. Improvements in these systems will also tend to
increase overall levels of power system reliability, providing a more secure business
environment for wholesale power markets
and enabling utilities to offer better service to their customers.
EPRI and its members have defined a
set of general objectives for the PowerSec Initiative, the first of which is to develop an overview of the electric power
industry’s current cyber security posture.
From this, the initiative will provide utilities with a list of vulnerabilities for each
major type of SCADA and EMS control
system commonly deployed across North
America and will tailor this information to reflect the particular combinations of systems in use. A comprehensive,
prioritized list of viable cyber threats will
also be developed, along with the compendium of best practices with recommendations on how to maximize cyber
security using currently available tools
and methods. A compendium of current
cyber security projects being pursued by
both government and private industry
will be developed to clarify which areas
are being adequately studied and which
need more attention.
Together, these results will be used to
identify gaps between viable threats and
defenses, both current and planned; the
analysis will lead to an R&D action plan
for developing technologies to eliminate
any gaps, identified or perceived.
Clearly the first order of business for
PowerSec will be to assess the vulnerability of information and control systems
currently used by utilities and system
operators. This work will begin with onsite interviews and inspections and will
be supplemented by evaluation of past or
ongoing security analyses by individual
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Artificial intelligence software offers new tools to help identify
physical threats. In this airport baggage claim area, a video
surveillance camera is able to automatically monitor and
analyze the activities of groups and individuals. When the man
circled in yellow sits down and then leaves the scene without the
small bag he was carrying, the system identifies the unattended
object (red box) and alerts security that there is a suspicious
situation. (Photos courtesy ActivEye, Inc.)
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utilities, EPRI, and government organizations. Researchers will also examine
existing information systems directly to
determine their cyber vulnerability, and
in some cases, conduct “red teaming”
(mock intrusion) exercises at selected host
utility sites. Particular emphasis will be
placed on examining SCADA and EMS
systems to help prevent hackers from using them to take over control of critical
utility equipment.
Each PowerSec participant will receive
a confidential document identifying the
strengths and weaknesses of its own SCADA and EMS systems. Because the report
will identify the best practices for those
particular systems, PowerSec participants
will have the advantage of being able to
enact available countermeasures immediately to reduce the threat of successful
cyber attack.
Information gleaned from the vulnerability assessment process is also intended
to complement ongoing security standards development by the North American Electric Reliability Council (NERC)
and the Federal Energy Regulatory Commission. The Urgent Action Cyber Security Standard 1200 adopted by NERC in
2003 already specifies actions to be taken
to protect utility systems in 16 areas, such
as access control, information protection,
personnel training, incident response, and
recovery planning, among others. This
stan­dard, which was originally adopted
as a temporary measure, is now being
­extended and modified for development
into a set of permanent security standards:
CIP-002 through CIP-009.
PowerSec’s assessment phase—expected
to take about a year—will provide an
ob­jec­tive assessment of the industry’s cyber security. If significant security gaps
are identified, EPRI staff will work with
PowerSec participants to propose solution
approaches to be developed and tested in
later phases.
The effectiveness of PowerSec results
will be evaluated using independent testbed exercises at the Idaho National Laboratory and Sandia National Laboratory, as
appropriate. These facilities are capable of
testing the new tools on a variety of SCADA and other cyber systems provided
by manufacturers. Evaluations will also
be conducted at individual utilities. The
PowerSec team will use the confidential
results of these evaluations, together with
feedback from the deployment process,
to revise vulnerability assessments and
enhance the alert system by adding new
attack mitigation actions.
An Eye to the Future
After developing the draft proposal for
the PowerSec Initiative, EPRI submitted
the plans to member utility executives for
comment and suggestions. This feedback
provided important insights on how to
proceed with PowerSec formation. The
comments revealed that utilities believe
they have made considerable progress
toward protecting their own cyber systems but recognize that key vulnerabilities remain across the industry as a whole.
The executives generally believe that
cy­ber attacks are likely, from domestic
and/or international terrorists, and that
disgruntled past or present employees also
represent a potentially dangerous threat.
They also say that PowerSec should ultimately address a combination of cyber
and physical threats and vulnerabilities,
because successful physical attacks may
involve very long recovery times. An area
of particular concern is how to ensure the
availability of spare parts for long-leadtime equipment.
The PowerSec Initiative will help participants come quickly up the learning
curve about cyber security risks and vulnerabilities and will give them enhanced
capabilities to assess cyber-related threats
on their own systems. Access to government and regulatory thinking on security
issues could also help participants better
prepare for potential changes in cyber
regulations that impact utilities. “The
biggest issue today is the incomplete and
anecdotal aspects of the situational data
available,” concludes Schainker. “Such
uncertainties prevent utilities from posi-
Loss of a high-voltage transformer is of particular concern for grid security because replacement
units typically take one to two years to procure, build, and install. EPRI’s Infrastructure Security
Initiative is dealing with this problem by sponsoring designs for a smaller, lighter “recovery
transformer” for emergency use that can be easily stored, transported, and installed in days.
(Courtesy ABB)
tioning themselves effectively for dealing
with security issues. A more comprehensive understanding of the situation will
allow PowerSec participants to better allocate financial and personnel resources to
their security preparedness.” Ultimately,
it is hoped that PowerSec will help focus
future government cyber security regulations, spur the development of innovative
mitigation tools and methods, and promote enhanced cyber security preparedness by the industry at large.
But if continued attacks on the grid are
inevitable, as many industry leaders believe, prevention will only be part of the
answer to grid security concerns. “We’ve
got a lot of smart people working on this
problem, but the field of opportunity for
intrusions is very broad,” says Wade Malcolm, EPRI’s vice president for power delivery. “We have to assume that sooner or
later an intruder will succeed in breaching our defenses. This is why a long-term
program for increasing overall system resiliency becomes crucial—if a hacker or
terrorist does manage to compromise a
transformer or power line, the grid must
be able to withstand the loss without the
danger of wide-area cascading outages.”
EPRI’s IntelliGridSM Consortium—another industrywide initiative—is working on adaptive, self-healing technologies
that can be built into the nation’s electric power delivery system to provide just
such resiliency.
“The industry is clearly entering a
new phase of security consciousness,”
concludes Schainker. “Some individual
utilities have already done a lot to protect their own cyber and physical systems against terrorist attacks, and now
the time has come to expand this work
through coordinated, industrywide efforts. If we are successful, the payoff will
be large indeed: With PowerSec reducing
the probable success of attacks and IntelliGrid features limiting the scope of their
effects, tomorrow’s power grid will have
every potential to meet the challenges of a
post-9/11 world.”
Background information for this article was
provided by Robert Schainker (rschaink@epri.
com) and Thomas Kropp (tkropp@epri.com).
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Technology at Work
TAG® Info Links Technology
With Business Planning
To implement strategic technological
solutions on their systems, utility planners must match appropriate technology
options with their ongoing business
­planning; making the right choices in
this process requires consistent, credible,
up-to-date information on the performance and cost of conventional and
emerging technologies. When it comes
to electricity generation technologies,
EPRI’s Technical Assessment Guide
(TAG®) is widely considered the industry
standard for such data, providing a level
of detail unavailable elsewhere. EPRI’s
data screening, sifting, and ­evaluation
process ensures credible, high-quality
information to serve the industry’s capital investment planning needs. As recent
experiences of Mid­American Energy
and East Kentucky Power Cooperative
demonstrate, TAG information can be
valuable in a great many applications,
from R&D and facilities engineering to
resource planning, market assessment,
and financial and legal issues.
MidAmerican Energy recently used
TAG to support its resource planning
and capital investment decisions related
to a number of development projects
in Iowa. TAG’s objective cost data on
alternative generation options formed
the basis for the company’s market price
forecasts, unit screening studies, and
economic expansion analyses. By providing MidAmerican with data that
would be time-consuming and expensive to develop independently, TAG was
able to substantially reduce the consultant fees and employee time required
for optimizing their capital investments.
Over the longer timeframe, TAG keeps
the company informed of emerging
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E P R I
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technologies and trends, providing
assistance in long-range capacity planning, financial plan development, asset
evaluations, long-term price modeling,
and response to regulatory inquiries.
One of TAG’s most valuable attributes
is its ability to consider the factors affecting a generation technology over each
stage of its life cycle. This long-term
perspective allows planners to assess a
technology’s technical and economic
­viability with respect to such factors as
fuel availability and cost, regulatory
climate, emissions control requirements,
and land and water issues. Such capa­
bility helps planners not only compare
the capital requirements associated
with different technologies, but also
­assess the risk/return aspects of a
decision over time.
Dale Stevens, manager of market
development for MidAmerican Energy,
actively promotes the use of TAG results
by other departments—for example, in
development of avoided capacity costs
for MidAmerican’s energy efficiency
plan—and is exploring customization of
the results for applications such as forecasting regional electricity market trends.
Meanwhile, East Kentucky Power
­Cooperative (EKPC) has been using
TAG for over a decade in developing
­regional case studies and benchmark
costs for inclusion in the resource planning documents it must file periodically
with the Kentucky Public Service Commission. More recently, it turned to
TAG to help with pressing resource planning and capital investment decisions
during a ­period of major growth. EKPC
used TAG to help determine the cost of
adding a new cooperative to its system,
pricing the new company’s assets both
independently and as part of the existing
Member applications of EPRI
science and technology
EKPC system. This approach proved
very beneficial in EKPC’s winning
­proposal to secure a new member for
the co-op.
“As a respected outside source of
information on technologies and costs,
the EPRI TAG has benefited East Kentucky Power Cooperative’s owners and
customers in many ways over the years,”
says EKPC’s Kim Hood. “TAG has
been a valuable tool that helps us make
informed decisions that optimize capital
investment, supports development of our
Integrated Resource Plan, and helps keep
EKPC’s power costs among the lowest
in the nation.”
For more information, contact G. (Ram)
Ramachandran, gramacha@epri.com.
Guided-Wave Sensor Surveys
Piping in San Antonio
City Public Service (CPS) of San
Antonio, Texas, has about three miles
of insulated, 12-inch-diameter piping
that supplies fuel oil to the boilers of its
VH Braunig plant. Two summers ago,
the piping developed a fuel leak caused
by corrosion under the insulation. The
standard approach for such a problem
would be to remove the insulation from
all three miles of piping and conduct
visual and ultrasonic inspections—an
expensive, time-consuming proposition.
CPS called on EPRI’s Fossil Nondestructive Evaluation (NDE) Center to
ask if there was a way to inspect the
piping for external corrosion without
insulation removal.
The NDE Center proposed using a
new long-range, guided-wave magnetostrictive sensor (MsS) system designed
to cost-effectively collect comprehensive
inspection information on long lengths
of power plant piping. The center had
recently evaluated the MsS system—
­developed by Southwest Research Institute—for buried pipe inspection, with
good results. MsS offered the potential
to conduct complete inspections, rather
than sampling, but without the need
to remove insulation or perform other
expensive preparations. CPS decided to
try the new technology to identify heavily corroded locations before the fuel oil
pipeline developed more leaks.
Over 1500 feet of piping were examined during the two-day MsS field trial:
straight runs, road crossings with elbows,
and elbows and straight sections associated with expansion loops. The tests
showed that some 300 feet of supply line
and 140 feet of return line were moderately to heavily corroded. CPS subsequently removed insulation from areas
indicated as having heavy corrosion and
confirmed the MsS results via conventional methods. In addition to accomplishing accurate inspection at low cost,
the guided-wave technology also avoided
the effort and cost of roadway excavation
for those pipe portions running under
roads, for a combined calculated cost
savings of $100,000.
Conventional inspection methods
would have required removal of all piping insulation, followed by visual and
ultrasonic examination—a process that
may have taken months to complete.
“MsS allowed us to screen large areas
of pipe in just a couple of days, and
that helped us quickly assess the cost of
replacing damaged piping,” notes CPS’s
Paul Barham.
For more information, contact Stan
Walker, swalker@epri.com.
Operator Training Simulator
Improves Skills, Reliability
In the modern digital economy, reliability of electric service is more important
than ever: loss of power brings computerbased business and manufacturing to
a standstill, with substantial financial
losses. Well-trained, highly skilled power
system operators are the first line of
defense against events that jeopardize
power system reliability. In light of this,
enhanced operator training has now been
mandated by the North American Electric Reliability Council—a direct result
of deficiencies in operator preparedness
identified in the Midwest and labeled
as one of the root causes of the August
2003 system blackout in the eastern
United States.
With reliability a top commitment
for its customer service, New York
Power Authority (NYPA) recently took
action to help its power system operators acquire the experience and skills
needed to manage systems on today’s
complex, highly interconnected power
grids. NYPA installed an EPRI/Siemens
Operator Training Simulator (OTS),
which realistically replicates the dynamic
behavior of a power system as it responds
to changes in operating conditions
or system events. The OTS’s systemspecific training scenarios help NYPA
supplement other training tools in the
development of a comprehensive operator
training program.
Functioning similarly to an aircraft
flight simulator, the OTS allows ­extreme
system situations to be presented to
trainees, enabling them to practice their
responses when there is no real conse­
quence for mistakes. Such exercises
accelerate the acquisition of experience
and skills needed to deal with real power
system emergencies. Because the train­ing scenarios were custom-developed
to reflect the workings of the NYPA
system, new operators can gain familiarity with both normal operations and
unexpected contingencies.
Initially, the OTS has been used as
a dispatch power flow tool that allows
trainees the opportunity to observe
real-time simulations of actual operator
actions performed in an interactive training environment. As training resources
are augmented at NYPA, the OTS will
be used more in the mode for which
it was originally designed, with the
system-specific training scenarios applied
in direct, one-on-one exercises. This
final phase of the coordinated training
program got under way earlier this year.
When broadly applied by the industry,
EPRI’s OTS will help ensure that power
system operators receive the training
they need to manage systems on today’s
complex grids and to deal confidently
with system emergencies.
For more information, contact David
Becker, dbecker@epri.com.
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Technical Reports & Software
Environment
Measuring and Monitoring Plans for Baseline
Development and Estimation of Carbon
Benefits for Change in Forest Management
in Two Regions
1011585 (Technical Report)
Program: Greenhouse Gas Reduction Options
EPRI Project Manager: Richard G. Rhudy
Chemical Constituents in Coal Combustion
Product Leachate: Boron
1005258 (Technical Report)
Program: Groundwater Protection and Coal
Combustion Products Management
EPRI Project Manager: Kenneth J. Ladwig
Baseline Greenhouse Gas Emissions and
Removals for Forest, Range, and Agricultural
Lands in California
1011586 (Technical Report)
Program: Greenhouse Gas Reduction Options
EPRI Project Manager: Richard G. Rhudy
Carbon Supply From Changes in Management
of Forest, Range, and Agricultural Lands of
California
1005465 (Technical Report)
Program: Greenhouse Gas Reduction Options
EPRI Project Manager: Richard G. Rhudy
Laboratory-Scale Evaluation of the Mercury
Chemical Reactions Across SCR Catalysts
1011649 (Technical Report)
Program: Plant Multimedia Toxics
Characterization (PISCES)
EPRI Project Manager: Paul Chu
EPRI Ergonomics Handbook for the Electric
Power Industry
1005574 (Technical Report)
Program: Occupational Health and Safety
EPRI Project Manager: Janice W. Yager
LARK-TRIPP RY2004, Version 1.1
1011997 (Software)
Program: Plant Multimedia Toxics
Characterization (PISCES)
EPRI Project Manager: Naomi L. Goodman
Reference Handbook for Site-Specific
Assessment of Subsurface Vapor Intrusion
to Indoor Air
1008492 (Technical Report)
Program: MGP Site Management
EPRI Project Manager: Babu Nott
Generation
For more information, contact the EPRI
Customer ­Assistance Center at 800.313.3774
(askepri@epri.com). Visit EPRI’s web site to
download PDF versions of technical reports
(www.epri.com).
Field Evaluation of Wedgewire Screens for
Protecting Early Life Stages of Fish at Cooling
Water Intakes
1010112 (Technical Report)
Program: Section 316(a) and 316(b) Fish
Protection Issues
EPRI Project Manager: Douglas A. Dixon
36
Metallurgical Guidebook for Fossil Power
Plant Boilers
1004509 (Technical Report)
Program: Fossil Materials and Repair
EPRI Project Manager: David W. Gandy
EPRI Coal Flow Loop: Evaluation of
Extractive Methods
1004744 (Technical Report)
Program: Combustion Performance and
NOx Control
EPRI Project Manager: Richard A. Brown
Impingement and Entrainment Survival
Studies Technical Support Document
1011278 (Technical Report)
Program: Section 316(a) and 316(b) Fish
Protection Issues
EPRI Project Manager: Douglas A. Dixon
Application of Strain Gage Technology for
Slag Deposition Monitoring
1004821 (Technical Report)
Program: I&C and Automation for Improved
Plant Operations
EPRI Project Manager: Ramesh Shankar
Entrainment Abundance Monitoring Technical
Support Document
1011280 (Technical Report)
Program: Section 316(a) and 316(b) Fish
Protection Issues
EPRI Project Manager: Douglas A. Dixon
Maintenance Task Work Package Library
1004828 (Technical Report)
Program: Maintenance Management
and Technology
EPRI Project Manager: Ray H. Chambers
E P R I
J O U R N A L
Guidelines for Performance-Based Contracts
for Fossil-Fueled Power Plants
1004829 (Technical Report)
Program: Maintenance Management
and Technology
EPRI Project Manager: Ray H. Chambers
Cycle Chemistry Guidelines for Fossil Plants:
Oxygenated Treatment
1004925 (Technical Report)
Program: Boiler and Turbine Steam and
Cycle Chemistry
EPRI Project Manager: Barry Dooley
Thermal Fatigue of Fossil Boiler Drum Nozzles
1008070 (Technical Report)
Program: Fossil Materials and Repair
EPRI Project Manager: Kent K. Coleman
Guidelines for Controlling Flow-Accelerated
Corrosion in Fossil and Combined-Cycle Plants
1008082 (Technical Report)
Programs: Boiler Life and Availability Improvement Program; Boiler and Turbine Steam and
Cycle Chemistry; Heat Recovery Steam
Generator (HRSG) Dependability
EPRI Project Manager: Barry Dooley
Diagnostic/Troubleshooting Monitoring
to Identify Damaging Cycle Chemistry or
Thermal Transients in Heat Recovery Steam
Generator Pressure Parts
1008088 (Technical Report)
Program: Heat Recovery Steam Generator
(HRSG) Dependability
EPRI Project Manager: Barry Dooley
Electromagnetic Nondestructive Evaluation
(NDE) for Heat Recovery Steam Generators
(HRSGs)
1008093 (Technical Report)
Program: Heat Recovery Steam Generator
(HRSG) Dependability
EPRI Project Manager: Stan M. Walker
Repair Welding Technologies for Heat
Recovery Steam Generators
1008094 (Technical Report)
Program: Heat Recovery Steam Generator
(HRSG) Dependability
EPRI Project Manager: David W. Gandy
Status and Performance of Best Available
Control Technologies
1008114 (Technical Report)
Program: Integrated Environmental Controls
(Hg, SO2, NOx, and Particulate)
EPRI Project Manager: Charles E. Dene
Materials Solutions for Waterwall Wastage—
An Update
1009618 (Technical Report)
Program: Combustion Performance and
NOx Control
EPRI Project Manager: Anthony Facchiano
Demonstration of Advanced Boiler
Instrumentation Technologies
1008144 (Technical Report)
Program: I&C and Automation for Improved
Plant Operations
EPRI Project Manager: Ramesh Shankar
2004 Workshop on Selective Catalytic
Reduction
1009627 (Technical Report)
Program: Post-Combustion NOx Control
EPRI Project Manager: David R. Broske
Operations Assessment Guideline
1008250 (Technical Report)
Program: Operations Management
and ­Technology
EPRI Project Manager: Wayne C. Crawford
Protecting Potentially Sensitive Information
1008261 (Technical Report)
Program: Operations Management
and ­Technology
EPRI Project Manager: Wayne C. Crawford
Quality Assurance/Quality Control Guidelines
for Mercury Measurements
1008267 (Technical Report)
Program: Continuous Emissions Monitoring
EPRI Project Manager: Charles E. Dene
Development of Code to Predict Stress
Corrosion Cracking and Corrosion Fatigue
of Low-Pressure Turbine Components
1009690 (Technical Report)
Program: Boiler and Turbine Steam and
Cycle Chemistry
EPRI Project Manager: Barry Dooley
FGD Remote Monitoring
1009772 (Technical Report)
Program: Integrated Environmental Controls
(Hg, SO2, NOx, and Particulate)
EPRI Project Manager: Ralph F. Altman
Generator On-Line Monitoring and Condition
Assessment: Partial Discharge
and Electromagnetic Interference
1010207 (Technical Report)
Program: Steam Turbines, Generators, and
Balance-of-Plant
EPRI Project Manager: Jan Stein
2005 EPRI Heat Rate Improvement Conference
1010321 (Technical Report)
Program: Combustion Performance and
NOx Control
EPRI Project Manager: Jeffrey Stallings
Catalyst Reaction (CATREACT) Version 1.0
1010332 (Software)
Program: Post-Combustion NOx Control
EPRI Project Manager: David R. Broske
SOAPP-REPO Combined-Cycle Repowering
Workstation, Version 3.0
1011032 (Software)
Program: New Combustion Turbine/CombinedCycle Design, Repowering, and Risk Mitigation
EPRI Project Manager: Dale S. Grace
Applications Guide for Guided Wave
Inspection Technology
1009776 (Technical Report)
Program: Fossil NDE Technology and Training
EPRI Project Manager: Stan M. Walker
Generator Expert Monitoring System
Knowledge Base
1011441 (Technical Report)
Program: Steam Turbines, Generators, and
Balance-of-Plant
EPRI Project Manager: Jan Stein
Hydropower Technology Roundup Report
1009798 (Technical Report)
Program: Hydropower, Emerging Issues
and Technologies
EPRI Project Manager: Douglas A. Dixon
Emission Control Options for Distributed
Resource Generators
1011482 (Technical Report)
Program: Distributed Energy Resources
EPRI Project Manager: Daniel M. Rastler
Gas Market Transition: Impacts of Power
Generation on Gas Pricing Dynamics
1008329 (Technical Report)
Program: Understanding Power and Fuel
­Markets and Generation Response
EPRI Project Manager: Jeremy B. Platt
Guidelines for the Development of an Initial
Systematic Training Program
1009849 (Technical Report)
Program: Workforce Training and
Development Research
EPRI Project Manager: Richard Pennington
RE Calculator 1.1—Renewables Calculator,
Version 1.1
1008367 (Software)
Program: Renewable Technology Options and
Green Power Marketing
EPRI Project Manager: Charles R. McGowin
Guidelines for the Evaluation of Cold
Reheat Piping
1009863 (Technical Report)
Program: Boiler Life and Availability
­Improvement Program
EPRI Project Manager: Richard Tilley
Numerical Simulation of Induced Flue Gas
Recirculation (IFGR) Operation at American
Electric Power’s Plant Welsh Unit 1
1011500 (Technical Report)
Program: Combustion Performance and
NOx Control
EPRI Project Manager: Richard A. Brown
Wind Power Integration: Energy Storage for
Firming and Shaping
1008388 (Technical Report)
Program: Renewable Technology Options and
Green Power Marketing
EPRI Project Manager: Charles R. McGowin
The Fate of Mercury Absorbed in Flue Gas
Desulfurization (FGD) Systems
1009955 (Technical Report)
Program: Integrated Environmental Controls
(Hg, SO2, NOx, and Particulate)
EPRI Project Manager: Richard G. Rhudy
Wind Power Integration: Smoothing ShortTerm Power Fluctuations
1008852 (Technical Report)
Program: Renewable Technology Options and
Green Power Marketing
EPRI Project Manager: Charles R. McGowin
All Eyes on LNG: U.S. Gas Supply Options
and Prospects for Relief
1009965 (Technical Report)
Program: Understanding Power and Fuel
Markets and Generation Response
EPRI Project Manager: Jeremy B. Platt
Combustion Turbine Guidelines: Conventional
and Advanced Machines
1008317 (Technical Report)
Program: Combustion Turbine (CT) and
­Combined-Cycle (CC) O&M
EPRI Project Manager: David W. Gandy
Solar Thermal Electric Technology in 2004
1011615 (Technical Report)
Program: Renewable Technology Options and
Green Power Marketing
EPRI Project Manager: Alejandro Jimenez
Advanced Steam Labyrinth Seal Design
1011932 (Technical Report)
Program: Steam Turbines, Generators, and
Balance-of-Plant
EPRI Project Manager: Stephen H. Hesler
Hydroelectric Assessment Study of Existing
and Planned Water Systems on the Big Island
1011993 (Technical Report)
Program: Renewable Technology Options and
Green Power Marketing
EPRI Project Manager: Alejandro Jimenez
S U M M E R
2 0 0 5
37
Biogas-Fueled Electric Power
1012019 (Technical Report)
Program: Distributed Energy Resources
EPRI Project Manager: David Thimsen
Risk-Informed Asset Management (RIAM)
1009632 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: George E. Sliter
Nuclear Power
2004 EDF/EPRI Collaboration on Life Cycle
Management and Nuclear Asset Management
1009634 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: George E. Sliter
Evaluation of Constant Elevated pH
Demonstration at Comanche Peak Steam
Electric Station
1003408 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Jeffrey C. Deshon
Materials Reliability Program: Destructive
Examination of the North Anna 2 Reactor
Pressure Vessel Head (MRP-142)
1007840 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Christine King
BWRVIP-140: BWR Vessel and Internals
Project, Fracture Toughness and Crack
Growth Program on Irradiated Austenitic
Stainless Steel
1008189 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Anne-Genevieve
Madelein Demma
Effect of Hydrazine on FlowAccelerated Corrosion
1008208 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Keith P. Fruzzetti
Initial Acceptance Criteria Concepts and Data
for Assessing Longevity of Low-Voltage Cable
Insulations and Jackets
1008211 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Gary J. Toman
Human Reliability Analysis Calculator
(HRA Calculator) Version 3.0
1008238 (Software)
Program: Nuclear Power
EPRI Project Manager: Frank J. Rahn
Life Cycle Management Sourcebook for
Nuclear Plant Service Water Systems
1008282 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Neil Wilmshurt
Cask Loader, Version 2.1
1009256 (Software)
Program: Nuclear Power
EPRI Project Manager: Marian McKenna
EPRI NDE Center Products Catalog
2004 Update
1009616 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Frank V. Ammirato
38
E P R I
J O U R N A L
Preliminary Development of Declarative
Modeling for Probabilistic Risk Assessments
1009644 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Ken Canavan
EOOS 3.4: Equipment Out of Service,
Version 3.4
1011195 (Software)
Program: Nuclear Power
EPRI Project Manager: Frank J. Rahn
CAFTA 5.2 Fault Tree Analysis System—Part
of R&R WS
1011196 (Software)
Program: Nuclear Power
EPRI Project Manager: Frank J. Rahn
FastTrack Generic Data Link Version 1.0
1011228 (Software)
Program: Nuclear Power
EPRI Project Manager: Sean P. Bushart
Generic Qualification and Dedication of
Digital Components
1009659 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Raymond C. Torok
Proceedings: 2004 EPRI International LowLevel Waste Conference and Exhibit Show
1011410 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Sean P. Bushart
Guidance for Performing a Simplified RiskInformed Turbine Missile Analysis
1009665 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Stephen H. Hesler
Proceedings: 2004 ASME/EPRI
Radwaste Workshop
1011411 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Sean P. Bushart
A Framework for the Treatment of External
Events in Configuration Risk Management
1009675 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: John P. Gaertner
BWRVIP-139: BWR Vessel and Internals
Project, Steam Dryer Inspection, and Flaw
Evaluation Guidelines
1011463 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Robert G. Carter
Analysis of Pressurized Water Reactor
Unqualified Original Equipment
Manufacturer Coatings
1009750 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Timothy Eckert
Spent Fuel Transportation Applications: Fuel
Rod Failure Evaluation Under Simulated Cask
Side Drop Conditions
1009929 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Albert J. Machiels
Qualification of Random-Wound Continuous
Duty Motor Insulating Systems, for Use in
Nuclear Power Plants—Test 1
1009972 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Leigh Aparicio
Failed-Fuel Analysis on Fuel Rods From
Exelon BWRs
1011100 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Kurt W. Edsinger
BWRVIP-18-A: BWR Vessel and Internals
Project, BWR Core Spray Internals Inspection
and Flaw Evaluation Guidelines
1011469 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Robert G. Carter
BWRVIP-42-A: BWR Vessel and Internals
Project, LPCI Coupling Inspection and Flaw
Evaluation Guideline
1011470 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Robert G. Carter
Analysis of the Thermal Hydraulics of Steam
Generators/Steam Generator Analysis
Package, Version 3.0-S
1011514 (Software)
Program: Nuclear Power
EPRI Project Manager: James M. Benson
BWRVIP-126, Rev. 1: BWR Vessel and
Internals Project, Radiation Analysis
Modeling Application Fluence Methodology,
Version 1.10
1011516 (Software)
Program: Nuclear Power
EPRI Project Manager: Robert G. Carter
Proceedings of the International
Conference on Water Chemistry of
Nuclear Reactor Systems
1011579 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Paul L. Frattini
Summary of Analytical Electron Microscopy
Observation of Intergranular Attack and
Stress Corrosion Cracks in Alloy 600 Steam
Generator Tubing
1011683 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Allan R. McIlree
BWRVIP-123, Revision 1: BWR Vessel and
Internals Project, Removal and Analysis of
Material Samples from Core Shroud and Top
Guide at Susquehanna Unit 2
1011695 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Robert G. Carter
Evaluating the Effects of Aging on Electronic
Instrument and Control Circuit Boards and
Components in Nuclear Power Plants
1011709 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Joseph A. Naser
Maine Yankee Decommissioning—
Experience Report
1011734 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Christopher Wood
Yucca Mountain Licensing Standard Options
for Very Long Time Frames
1011754 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: John Kessler
Program on Technology Innovation: EPRI
Yucca Mountain Total System Performance
Assessment Code (IMARC) Version 8
1011813 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: John Kessler
Neutron Transmission Through Boral™:
Impact of Channeling on Criticality
1011819 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Albert J. Machiels
Materials Reliability Program: Management
of Thermal Fatigue in Normally Stagnant
Non-Isolable Reactor Coolant System Branch
Lines (MRP-146)
1011955 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: John J. Carey
Pilot Study of Delta’s Mururoa Protective Suit
at McGuire Nuclear Power Station
1011970 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Dennis Hussey
BWRVIP-123: Revision 1NP: BWR Vessel and
Internals Project, Removal and Analysis of
Material Samples from Core Shroud and Top
Guide at Susquehanna Unit 2
1012016 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Robert G. Carter
Experience-Based Seismic Verification
Guidelines for Overhead Crane Systems
1012022 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Robert Kassawara
Experience-Based Seismic Verification
Guidelines for Piping Systems
1012023 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Robert Kassawara
Materials Reliability Program, Materials
Handbook for Nuclear Plant Pressure
Boundary Applications (MRP-150)
1012039 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Hui-Tsung Tang
Effect of Polymer Dispersant on
Flow-Accelerated Corrosion of
Steam Generator Materials
1012056 (Technical Report)
Program: Nuclear Power
EPRI Project Manager: Keith P. Fruzzetti
Power Delivery and Markets
Guide for Non-Destructive Diagnosis of
Distribution Cable Systems
1001731 (Technical Report)
Program: Underground Distribution Systems
EPRI Project Manager: Robert J. Keefe
Material Identity Card
1001865 (Technical Report)
Program: Underground Transmission Systems
EPRI Project Manager: Walter Zenger
Power Quality Diagnostic System (PQDS),
Version 1.4
1008502 (Software)
Program: Power Quality Analysis Tools
and Testing
EPRI Project Manager: Robert B. Schainker
Power Quality Implications of Transmission
and Distribution Construction
1008506 (Technical Report)
Program: Power Quality Solutions for
Transmission and Distribution
EPRI Project Manager: Robert B. Schainker
Power Quality Impacts of
Distributed Generation
1008507 (Technical Report)
Program: Power Quality Solutions for
Transmission and Distribution
EPRI Project Manager: Robert B. Schainker
Correlating Power Quality Indices With
System Reliability Indices
1008508 (Technical Report)
Program: Power Quality Solutions for
Transmission and Distribution
EPRI Project Manager: Robert B. Schainker
Development of a Framework for a Service
Quality Index
1008509 (Technical Report)
Program: Power Quality Solutions for
Transmission and Distribution
EPRI Project Manager: Robert B. Schainker
Automated Evaluation System for Capacitor
Switching Transient Concerns
1008510 (Technical Report)
Program: Power Quality Solutions for
Transmission and Distribution
EPRI Project Manager: Robert B. Schainker
Effects of Temporary Overvoltage on
Residential Products
1008540 (Technical Report)
Program: Power Quality Mitigative Solutions
EPRI Project Manager: Robert B. Schainker
Industrial Design Guide (IDG), Version 5.0
1008541 (Software)
Program: Power Quality Mitigative Solutions
EPRI Project Manager: Robert B. Schainker
Enhanced Ride-Through for Industrial
Power Supplies
1008544 (Technical Report)
Program: Power Quality Mitigative Solutions
EPRI Project Manager: Robert B. Schainker
Electricity Market Transformation: A Risk
Management Approach
1008549 (Technical Report)
Program: Electricity Market Transformation
EPRI Project Manager: Hung-po Chao
Asset Performance Database
1008553 (Technical Report)
Program: Power Delivery Asset Management
EPRI Project Manager: William J. Parkinson
Strategic Insights on Security, Quality,
Reliability, and Availability
1008566 (Technical Report)
Program: Strategic Management of Security,
Quality, Reliability, and Availability
EPRI Project Manager: Robert B. Schainker
S U M M E R
2 0 0 5
39
EPRI Events
For further event listings, visit EPRI’s web site
(www.epri.com).
August 2005
15–18
NMAC Large Electric Motor Users Group
and Workshop
New Haven, CT
Contact: Linda Parrish, 704.547.6061
16–18
Distribution Planning for Distributed Resources
and Automation
Knoxville, TN
Contact: Lisa Wolfenbarger, 865.218.8052
16–18
Reduce Transmission Maintenance Costs
and Expand Equipment Life
Palo Alto, CA
Contact: John Chan, 650.855.2452
17–18
EPRI/Regional Distribution Workshop
St. Louis, MO
Contact: Ron Diaz, 317.335.1797
17–18
Midwest Regional Distribution Workshop
St. Louis, MO
Contact: Ksenija Sobajic, 650.855.2621
17–19
8th FACTS User’s Group Meeting and TF14
Power Flow Management and Control
Stamford, CT
Contact: Angelica Kamau, 650.855.7987
17–19
Power Electronics-Based Controllers
Hartford, CT
Contact: Abdel-Aty Edris, 650.855.2311
18–19
EPRI Western Environmental Conference
Westminster, CO
Contact: Jeff Crowe, 650.855.8907 22–24
EPRI Workforce Training and Development
Working Group
St. Louis, MO
Contact: EPRI Order Management,
eprievents@epri.com
40
E P R I
J O U R N A L
22–25
Nuclear Power Advisory Meetings
Chicago, IL
Contact: Melissa Wade, 704.547.6043
22–26
EPRI Turbine/Generator Meeting
Denver, CO
Contact: Linda Parrish, 704.547.6061
23
Overhead Transmission Design for Optimized
Life-Cycle Costs
Web Conference
Contact: John Chan, 650.855.2452
23–24
Excitation System Maintenance,
Refurbishment, and On-line Testing/
Calibration
Denver, CO
Contact: Linda Parrish, 704.547.6061
24
Fuel Reliability Program Senior Repre­
sentatives and Executive Committee Meeting
Chicago, IL
Contact: Melissa Wade, 704.547.6043
24
Utility Workshop Focused on Today’s
Customers and Their Future Needs
Charlotte, NC
Josephine Garcia, 650.855.8619
24–26
NMAC Protective and Auxiliary Relay
Industry Meeting
Spokane, WA
Contact: Linda Parrish, 704.547.6061
30–September 1
Condenser Technology Seminar
and Conference
San Diego, CA
Contact: Megan Wheeler, 415.455.9583
31
Fleet-Wide Monitoring
Web Conference
Contact: Ramesh Shankar, 704.547.6127
September 2005
1–2
Fuel Reliability Program Working
Group 1 Meeting
Las Vegas, NV
Contact: Evelyn Simons, 650.855.2728
7–9
JUTG Procurement Forum
Chicago, IL
Contact: Elizabeth Marlowe, 704.547.6036
12–16
Environment Sector and Area Council
Advisory Meetings
St. Louis, MO
Contact: Randy Michaud, 650.855.2919
12–16
Service Water Heat Exchanger Testing
Training Course
Charlotte, NC
Contact: Elizabeth Marlowe, 704.547.6036
13
Reduce Transmission Maintenance Costs
and Expand Equipment Life
Web Conference
Contact: John Chan, 650.855.2452
13–15
EPRI/INPO 2005 Chemistry
Managers Workshop
Marietta, GA
Contact: Sara Cruz, 770.644.8378
14
High-Power Transmission and Substation
Electromagnetic Compatibility (EMC)
Charlotte, NC
Contact: Brian Cramer, 815.478.5344
16
Power Electronics–Based Controllers
Web Conference
Contact: Abdel-Aty Edris, 650.855.2311
19–20
BWR Condensate Filter Users Group Meeting
Nashville, TN
Contact: Mary Jarvis, 315.698.0834
19–21
Generation Program Advisory
Committee Meeting
Addison, TX
Contact: Carol Holt, 650.855.2436 4–5
NMAC Hoisting, Rigging, and Crane Users
Group Meeting
Charlotte, NC
Contact: Linda Parrish, 704.547.6061
20–21
Power Delivery Applications for
Superconductivity
Albany, NY
Contact: Steve Eckroad, 704.717.6424
5
Switching Safety and Reliability Taskforce
Phoenix, AZ
Contact: Ben Damsky, 650.855.2385
27–28
Research Advisory Committee
San Francisco, CA
Contact: Barbara Ryan, 608.513.4494
27–28
Transformer Life Management
Memphis, TN
Contact: Barry Ward, 650.855.2717
31–November 3
Improving Power Quality
Knoxville, TN
Contact: Lisa Wolfenbarger, 865.218.8026
20–22
2005 Condensate Polishing Workshop
Nashville, TN
Contact: Linda Nelson, 518.374.8190
5–7
2005 Technology Management Committee
(TMC) Meetings
Knoxville, TN
Contact: Tonia Biggs, 614.880.5044
21–23
Valuing Generation Assets
Washington, DC
Contact: EPRI Order Management,
eprievents@epri.com
6
Power Delivery Applications for
Superconductivity
Web Conference
Contact: Steve Eckroad, 704.717.6424
22–23
Generation Council Meeting
Dallas, TX
Contact: Peggy Roper, 650.855.2133
12
Switching Safety and Reliability
Web Conference
Contact: Ben Damsky, 650.855.2385
3–4
Improve Transmission Line
Lightning Performance
Charlotte, NC
Contact: Andrew Phillips, 704.717.6438
22–23
Underground Transmission Task Force
Albany, NY
Contact: Walter Zenger, 413.448.2424
14
Improve Overall Substation
Maintenance Optimization
Web Conference
Contact: Barry Ward, 650.855.2717
3–4
Overhead Transmission Design for
Optimized Life-Cycle Costs
Charlotte, NC
Contact: John Chan, 650.855.2452
18
Insulators
Web Conference
Contact: Andrew Phillips, 704.717.6438
4
High-Power Transmission and Substation
Electromagnetic Compatibility (EMC)
Web Conference
Contact: Brian Cramer, 815.478.5344
26–28
PSAPO Advisory Council Meeting
Charlotte, NC
Contact: Angelica Kamau, 650.855.7987
26–28
Transmission and Distribution Area
Council Meeting
Charlotte, NC
Contact: Ray Lings, 650.855.2177
29–30
Power Delivery and Markets Council Meeting
Charlotte, NC
Contact: Josephine Garcia, 650.855.8619
29–30
Value and Risk in Energy Markets
Advisory Meeting
Charlotte, NC
Contact: Josephine Garcia, 650.855.8619
October 2005
3–4
Switching Safety and Reliability
Phoenix, AZ
Contact: George Gela, 413.499.5710
3–5
Wireless Technology
Jersey City, NJ
Contact: Lynette Gulledge, 704.547.6194
18–20
Value and Risk in Energy Markets
Palo Alto, CA
Contact: EPRI Order Management,
eprievents@epri.com
November 2005
1–2
Insulators
Charlotte, NC
Contact: Andrew Phillips, 704.717.6438
7
Transformer Life Management
Web Conference
Contact: Barry Ward, 650.855.2717
19
Increased Power Flow
Web Conference
Contact: Ram Adapa, 650.855.8988
8
EPRI On-Line Monitoring Users Group Meeting
Charlotte, NC
Contact: Ramesh Shankar, 704.547.6127
20
Improve Transmission Line
Lightning Performance
Web Conference
Contact: Andrew Phillips, 704.717.6438
9–10
Improve Safe Live-Line Maintenance
Work Practices
Lenox, MA
Contact: Andrew Phillips, 704.717.6438
20–21
Energy Storage for T&D Applications
San Francisco, CA
Contact: Steve Eckroad, 704.717.6424
14
Energy Storage for T&D Applications
Web Conference
Contact: Steve Eckroad, 704.717.6424
25
Underground Transmission Task Force
Web Conference
Contact: Walter Zenger, 413.448.2424
15–17
2005 Workshop on Selective Catalytic
Reduction Meeting
Louisville, KY
Contact: Katy Ahrens, 415.455.9583
ELECTRIC POWER RESEARCH INSTITUTE
SUMMER 2005
ELECTRIC POWER
RESEARCH INSTITUTE
Post Office Box 10412
Palo Alto, California 94303-0813
NONPROFIT ORGANIZATION
U.S. POSTAGE
PAID
SALEM OR,
PERMIT NUMBER 526
ADDRESS SERVICE REQUESTED
Printed on recycled paper in the United States of America
1012149